Systems and methods for high volumetric oxidant flow in gas turbine engine with exhaust gas recirculation

ABSTRACT

A system having a gas turbine engine is provided. The gas turbine engine includes a turbine and a combustor coupled to the turbine. The combustor includes a combustion chamber, one or more fuel nozzles upstream from the combustion chamber, and a head end having an end cover assembly. The end cover assembly includes an oxidant inlet configured to receive an oxidant flow, a central oxidant passage, and at least one fuel supply passage. The central oxidant passage is in fluid communication with the oxidant inlet, and the central oxidant passage is configured to route the oxidant flow to the one or more fuel nozzles. The at least one fuel supply passage is configured to receive a fuel flow and route the fuel flow into the one or more fuel nozzles.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and benefit of U.S. Provisional Patent Application No. 62/112,129, entitled “SYSTEMS AND METHODS FOR HIGH VOLUMETRIC OXIDANT FLOW IN GAS TURBINE ENGINE WITH EXHAUST GAS RECIRCULATION,” filed on Feb. 4, 2015, which is incorporated by reference herein in its entirety for all purposes.

BACKGROUND

The subject matter disclosed herein relates to gas turbines, and more specifically, to gas turbines with exhaust gas recirculation.

Gas turbine engines are used in a wide variety of applications, such as power generation, aircraft, and various machinery. Gas turbine engines generally combust a fuel with an oxidant (e.g., air) in a combustor section to generate hot combustion gases, which then drive one or more turbine stages of a turbine section. In turn, the turbine section drives one or more compressor stages of a compressor section, thereby compressing oxidant for intake into the combustor section along with the fuel. Again, the fuel and oxidant mix in the combustor section, and then combust to produce the hot combustion gases. The oxidant (e.g., air) may be used to cool components of the combustor section. Unfortunately, use of the oxidant (e.g., air) for cooling may complicate the control of oxidant concentration in the combustion region and/or in the combustion gases.

BRIEF DESCRIPTION

Certain embodiments commensurate in scope with the originally claimed invention are summarized below. These embodiments are not intended to limit the scope of the claimed invention, but rather these embodiments are intended only to provide a brief summary of possible forms of the invention. Indeed, the invention may encompass a variety of forms that may be similar to or different from the embodiments set forth below.

In a first embodiment, a system having a gas turbine engine is provided. The gas turbine engine includes a turbine and a combustor coupled to the turbine. The combustor includes a combustion chamber, one or more fuel nozzles upstream from the combustion chamber, and a head end having an end cover assembly. The end cover assembly includes an oxidant inlet configured to receive an oxidant flow, a central oxidant passage, and at least one fuel supply passage. The central oxidant passage is in fluid communication with the oxidant inlet, and the central oxidant passage is configured to route the oxidant flow to the one or more fuel nozzles. The at least one fuel supply passage is configured to receive a fuel flow and route the fuel flow into the one or more fuel nozzles.

In a second embodiment, a system including an end cover assembly is provided. The end cover assembly is configured to mount at a head end of a turbine combustor. The end cover assembly includes an oxidant inlet, a central oxidant passage, and at least one fuel supply passage. The oxidant inlet configured to receive an oxidant flow. The central oxidant passage in fluid communication with the oxidant inlet and is configured to route the oxidant flow to one or more fuel nozzles. The at least one fuel supply passage configured to receive a fuel flow, where the at least one fuel supply passage is configured to route the fuel flow into the one or more fuel nozzles.

In a third embodiment, a method is provided. The method includes receiving an oxidant flow into an oxidant inlet of an end cover assembly of a turbine combustor of a gas turbine engine. The method also includes routing the oxidant flow from the oxidant inlet through a central oxidant passage in the end cover assembly and distributing the oxidant flow from the central oxidant passage into a plurality of fuel nozzles.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 is a diagram of an embodiment of a system having a turbine-based service system coupled to a hydrocarbon production system;

FIG. 2 is a diagram of an embodiment of the system of FIG. 1, further illustrating a control system and a combined cycle system;

FIG. 3 is a diagram of an embodiment of the system of FIGS. 1 and 2, further illustrating details of a gas turbine engine, exhaust gas supply system, and exhaust gas processing system;

FIG. 4 is a flow chart of an embodiment of a process for operating the system of FIGS. 1-3;

FIG. 5 is a schematic diagram of an embodiment of a combustor section of the gas turbine engine of FIG. 3, illustrating an end cover assembly having a central oxidant passage, a baffle assembly, an extended casing system, and a fuel supply system;

FIG. 6 is a schematic diagram of an embodiment of the end cover assembly of FIG. 5, illustrating a compressed oxidant provided to the gas turbine engine of FIG. 3 through the central oxidant passage;

FIG. 7 is a schematic diagram of an embodiment of the central oxidant passage of FIG. 6, where the central oxidant passage includes a flow conditioner configured to route the oxidant to the baffle assembly;

FIG. 8 is a schematic diagram of an embodiment of the central oxidant passage of FIG. 6 configured to route the oxidant to the baffle assembly;

FIG. 9 is a schematic diagram of an embodiment of the extended casing system of FIG. 6, where the extended casing system includes a flange, an outer expansion wall, an inner expansion wall, and a flex space; and

FIG. 10 is a cross-sectional view of an embodiment of the end cover assembly of FIG. 5, illustrating the fuel supply system having a plurality of fuel supply passages.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in an engineering or design project, numerous implementation-specific decisions are made to achieve the specific goals, such as compliance with system-related and/or business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Detailed example embodiments are disclosed herein. However, specific structural and functional details disclosed herein are merely representative for purposes of describing example embodiments. Embodiments of the present invention may, however, be embodied in many alternate forms, and should not be construed as limited to only the embodiments set forth herein.

Accordingly, while example embodiments are capable of various modifications and alternative forms, embodiments thereof are illustrated by way of example in the figures and will herein be described in detail. It should be understood, however, that there is no intent to limit example embodiments to the particular forms disclosed, but to the contrary, example embodiments are to cover all modifications, equivalents, and alternatives falling within the scope of the present invention.

The terminology used herein is for describing particular embodiments only and is not intended to be limiting of example embodiments. As used herein, the singular forms “a”, “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises”, “comprising”, “includes” and/or “including”, when used herein, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

Although the terms first, second, primary, secondary, etc. may be used herein to describe various elements, these elements should not be limited by these terms. These terms are only used to distinguish one element from another. For example, but not limiting to, a first element could be termed a second element, and, similarly, a second element could be termed a first element, without departing from the scope of example embodiments. As used herein, the term “and/or” includes any, and all, combinations of one or more of the associated listed items.

Certain terminology may be used herein for the convenience of the reader only and is not to be taken as a limitation on the scope of the invention. For example, words such as “upper”, “lower”, “left”, “right”, “front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”, “downstream”, “fore”, “aft”, and the like; merely describe the configuration shown in the figures. Indeed, the element or elements of an embodiment of the present invention may be oriented in any direction and the terminology, therefore, should be understood as encompassing such variations unless specified otherwise.

As discussed in detail below, the disclosed embodiments relate generally to gas turbine systems with exhaust gas recirculation (EGR), and particularly stoichiometric operation of the gas turbine systems using EGR. For example, the gas turbine systems may be configured to recirculate the exhaust gas along an exhaust recirculation path, stoichiometrically combust fuel and oxidant along with at least some of the recirculated exhaust gas, and capture the exhaust gas for use in various target systems. The recirculation of the exhaust gas along with stoichiometric combustion may help to increase the concentration level of carbon dioxide (CO₂) in the exhaust gas, which can then be post treated to separate and purify the CO₂ and nitrogen (N₂) for use in various target systems. The gas turbine systems also may employ various exhaust gas processing (e.g., heat recovery, catalyst reactions, etc.) along the exhaust recirculation path, thereby increasing the concentration level of CO₂, reducing concentration levels of other emissions (e.g., carbon monoxide, nitrogen oxides, and unburnt hydrocarbons), and increasing energy recovery (e.g., with heat recovery units). Furthermore, the gas turbine engines may be configured to combust the fuel and oxidant with one or more diffusion flames (e.g., using diffusion fuel nozzles), premix flames (e.g., using premix fuel nozzles), or any combination thereof. In certain embodiments, the diffusion flames may help to maintain stability and operation within certain limits for stoichiometric combustion, which in turn helps to increase production of CO₂. For example, a gas turbine system operating with diffusion flames may enable a greater quantity of EGR, as compared to a gas turbine system operating with premix flames. In turn, the increased quantity of EGR helps to increase CO₂ production. Possible target systems include pipelines, storage tanks, carbon sequestration systems, and hydrocarbon production systems, such as enhanced oil recovery (EOR) systems.

The disclosed embodiments generally relate to an end cover assembly coupled to a head end of the gas turbine engine. In particular, the end cover assembly may be configured to route an oxidant and a fuel through the head end portion of the gas turbine engine and into one or more fuel nozzles. In certain embodiments, the oxidant may be a compressed oxidant comprising a compressed air, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any combination thereof. The one or more fuel nozzles are housed in the head end portion of the gas turbine engine and may be configured to receive the oxidant, the fuel, and in some situations, an exhaust gas, and may inject streams or mixtures of the exhaust gas, the oxidant, and/or the fuel into a combustion portion (e.g., combustion chamber) of the combustor. The one or more fuel nozzles may include any combination of premix fuel nozzles (e.g., configured to premix the oxidant and fuel for generation of an oxidant/fuel premix flame) and/or diffusion fuel nozzles (e.g., configured to inject separate flows of the oxidant and fuel for generation of an oxidant/fuel diffusion flame).

In certain embodiments, the end cover assembly includes a central oxidant passage, a baffle assembly, an extended casing system, and a fuel supply system. In particular, the end cover assembly may be configured to axially receive and route a range of volumetric flows (e.g., high volumetric flows of oxidant and/or low volumetric flows of oxidant) through the head end portion of the combustor. For example, in certain embodiments, the central oxidant passage of the end cover assembly may be configured to receive a supply of oxidant utilized by the combustor to sustain a combustion process during operation of the combustor. In particular, the supply of oxidant utilized by the combustion process may be axially routed through the central oxidant passage of the end cover assembly. In this embodiment, the central oxidant passage of the end cover assembly may be configured to receive a high volumetric mass flow of the oxidant at a single location (e.g., at the central oxidant passage) of the head end portion of the combustor, such as an amount of oxidant volumetric flow sufficient to sustain the combustion process during operation of the combustor. In certain embodiments, the central oxidant passage of the end cover assembly may be configured to receive a low volumetric flow of oxidant through the head end portion, such as any portion of oxidant supply utilized to operate the combustion process of the combustor.

It should be noted that in certain embodiments, the central oxidant passage is configured to receive and route a range of volumetric flows of a supply of oxidant at high temperatures. For example, the central oxidant passage may be configured to receive a high volumetric mass flow of the oxidant both at a single location and at high temperatures without causing major thermal stress. In certain embodiments, the central oxidant passage may include a heat shield and/or a flow conditioner to allow the central oxidant passage to receive and route an high volumetric mass flow of oxidant at the higher temperatures. In this manner, the central oxidant passage may provide high volumetric flows of oxidant sufficient to sustain the combustion process during operation of the combustor and also protect various components of the endcover assembly from thermal strains and/or thermal distortions that may occur with high volumetric flows of fluids at high temperatures. Indeed, in certain embodiments, the heat shield and/or the flow conditioner of the central oxidant passage may be configured to substantially thermally isolate the central oxidant passage from various components of the end cover assembly, thereby allowing the central oxidant passage to receive and route a range of volumetric flows. Accordingly, the disclosed embodiments generally disclose an end cover assembly configured to receive the oxidant supply at a single central location (e.g., the central oxidant passage) within the head end portion of the combustor, rather than through various locations throughout the head end portion of the combustor. Further, the end cover assembly may be configured to receive a range of oxidant volumetric flows at high temperatures the single central location (e.g., the central oxidant passage).

In certain embodiments, the supply of oxidant received at the central oxidant passage at the end cover assembly may be routed into a baffle assembly of the end cover assembly. Particularly, the baffle assembly may include a plurality of oxidant holes configured to route and direct the supply of oxidant through the end cover assembly and into each of the one or more fuel nozzles. Further, in certain embodiments, the end cover assembly includes a fuel supply system. The fuel supply system includes an outer fuel nozzles supply inlet, a central fuel nozzle supply inlet, one or more fuel supply passages, and the plurality of fuel nozzles. In particular, the fuel supply system may be configured to route a fuel through the head end portion of the combustor and to each of the plurality of nozzles. Specifically, the fuel supply system may be configured to route the fuel through the end cover assembly, such as from the outer and central fuel supply inlets, through each of the fuel supply passages, and into each of the plurality of fuel nozzles.

In certain embodiments, the end cover assembly includes an extended casing system (e.g., housing) configured to define a volume of space that houses the central oxidant passage, a baffle assembly, and the fuel supply system. In particular, the extended casing system includes a flange (e.g., annular flange), an outer expansion wall (e.g., annular wall), an inner expansion wall (e.g., annular wall), and a flex space. In certain embodiments, the flange may be configured to couple and secure the end cover assembly to a portion of the compressor section of the gas turbine engine. Further, in certain embodiments, the outer expansion wall of the end cover assembly may be arranged to increase the volume of space within the end cover assembly to house components of the end cover assembly. In particular, in certain embodiments, the outer expansion wall and the inner expansion wall of the end cover assembly may be configured to provide flexibility (e.g., thermal expansion and contraction) for the components of the end cover assembly during operation of the combustor. Specifically, during operation of the combustor, the end cover assembly may be configured to receive fluids of varying temperatures and pressures, e.g., hot and cold fluids in proximity to one another, while providing flexibility to accommodate thermal expansion and contraction caused by temperature gradients. For example, the end cover may supply an oxidant to the central oxidant passage at high temperatures (e.g., caused by compression), while the end cover may feed a fuel at low temperatures (e.g., ambient temperature). Accordingly, the disclosed embodiments provide a casing system configured to flex or expand in response to thermal strains and/or temperature gradients among the components of the end cover assembly. Further, the disclosed embodiments generally provide internal heat shields or thermal insulation grooves that are configured to substantially thermally isolate or insulate certain components of the end cover assembly.

FIG. 1 is a diagram of an embodiment of a system 10 having a hydrocarbon production system 12 associated with a turbine-based service system 14. As discussed in further detail below, various embodiments of the turbine-based service system 14 are configured to provide various services, such as electrical power, mechanical power, and fluids (e.g., exhaust gas), to the hydrocarbon production system 12 to facilitate the production or retrieval of oil and/or gas. In the illustrated embodiment, the hydrocarbon production system 12 includes an oil/gas extraction system 16 and an enhanced oil recovery (EOR) system 18, which are coupled to a subterranean reservoir 20 (e.g., an oil, gas, or hydrocarbon reservoir). The oil/gas extraction system 16 includes a variety of surface equipment 22, such as a Christmas tree or production tree 24, coupled to an oil/gas well 26. Furthermore, the well 26 may include one or more tubulars 28 extending through a drilled bore 30 in the earth 32 to the subterranean reservoir 20. The tree 24 includes one or more valves, chokes, isolation sleeves, blowout preventers, and various flow control devices, which regulate pressures and control flows to and from the subterranean reservoir 20. While the tree 24 is generally used to control the flow of the production fluid (e.g., oil or gas) out of the subterranean reservoir 20, the EOR system 18 may increase the production of oil or gas by injecting one or more fluids into the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34, which has one or more tubulars 36 extending through a bore 38 in the earth 32 to the subterranean reservoir 20. For example, the EOR system 18 may route one or more fluids 40, such as gas, steam, water, chemicals, or any combination thereof, into the fluid injection system 34. For example, as discussed in further detail below, the EOR system 18 may be coupled to the turbine-based service system 14, such that the system 14 routes an exhaust gas 42 (e.g., substantially or entirely free of oxygen) to the EOR system 18 for use as the injection fluid 40. The fluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42) through the one or more tubulars 36 into the subterranean reservoir 20, as indicated by arrows 44. The injection fluid 40 enters the subterranean reservoir 20 through the tubular 36 at an offset distance 46 away from the tubular 28 of the oil/gas well 26. Accordingly, the injection fluid 40 displaces the oil/gas 48 disposed in the subterranean reservoir 20, and drives the oil/gas 48 up through the one or more tubulars 28 of the hydrocarbon production system 12, as indicated by arrows 50. As discussed in further detail below, the injection fluid 40 may include the exhaust gas 42 originating from the turbine-based service system 14, which is able to generate the exhaust gas 42 on-site as needed by the hydrocarbon production system 12. In other words, the turbine-based system 14 may simultaneously generate one or more services (e.g., electrical power, mechanical power, steam, water (e.g., desalinated water), and exhaust gas (e.g., substantially free of oxygen)) for use by the hydrocarbon production system 12, thereby reducing or eliminating the reliance on external sources of such services.

In the illustrated embodiment, the turbine-based service system 14 includes a stoichiometric exhaust gas recirculation (SEGR) gas turbine system 52 and an exhaust gas (EG) processing system 54. The gas turbine system 52 may be configured to operate in a stoichiometric combustion mode of operation (e.g., a stoichiometric control mode) and a non-stoichiometric combustion mode of operation (e.g., a non-stoichiometric control mode), such as a fuel-lean control mode or a fuel-rich control mode. In the stoichiometric control mode, the combustion generally occurs in a substantially stoichiometric ratio of a fuel and oxidant, thereby resulting in substantially stoichiometric combustion. In particular, stoichiometric combustion generally involves consuming substantially all of the fuel and oxidant in the combustion reaction, such that the products of combustion are substantially or entirely free of unburnt fuel and oxidant. One measure of stoichiometric combustion is the equivalence ratio, or phi (φ), which is the ratio of the actual fuel/oxidant ratio relative to the stoichiometric fuel/oxidant ratio. An equivalence ratio of greater than 1.0 results in a fuel-rich combustion of the fuel and oxidant, whereas an equivalence ratio of less than 1.0 results in a fuel-lean combustion of the fuel and oxidant. In contrast, an equivalence ratio of 1.0 results in combustion that is neither fuel-rich nor fuel-lean, thereby substantially consuming all of the fuel and oxidant in the combustion reaction. In context of the disclosed embodiments, the term stoichiometric or substantially stoichiometric may refer to an equivalence ratio of approximately 0.95 to approximately 1.05. However, the disclosed embodiments may also include an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03, 0.04, 0.05, or more. Again, the stoichiometric combustion of fuel and oxidant in the turbine-based service system 14 may result in products of combustion or exhaust gas (e.g., 42) with substantially no unburnt fuel or oxidant remaining. For example, the exhaust gas 42 may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. By further example, the exhaust gas 42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. However, the disclosed embodiments also may produce other ranges of residual fuel, oxidant, and other emissions levels in the exhaust gas 42. As used herein, the terms emissions, emissions levels, and emissions targets may refer to concentration levels of certain products of combustion (e.g., NO_(X), CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculated gas streams, vented gas streams (e.g., exhausted into the atmosphere), and gas streams used in various target systems (e.g., the hydrocarbon production system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54 may include a variety of components in different embodiments, the illustrated EG processing system 54 includes a heat recovery steam generator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58, which receive and process an exhaust gas 60 originating from the SEGR gas turbine system 52. The HRSG 56 may include one or more heat exchangers, condensers, and various heat recovery equipment, which collectively function to transfer heat from the exhaust gas 60 to a stream of water, thereby generating steam 62. The steam 62 may be used in one or more steam turbines, the EOR system 18, or any other portion of the hydrocarbon production system 12. For example, the HRSG 56 may generate low pressure, medium pressure, and/or high pressure steam 62, which may be selectively applied to low, medium, and high pressure steam turbine stages, or different applications of the EOR system 18. In addition to the steam 62, a treated water 64, such as a desalinated water, may be generated by the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 or the SEGR gas turbine system 52. The treated water 64 (e.g., desalinated water) may be particularly useful in areas with water shortages, such as inland or desert regions. The treated water 64 may be generated, at least in part, due to the large volume of air driving combustion of fuel within the SEGR gas turbine system 52. While the on-site generation of steam 62 and water 64 may be beneficial in many applications (including the hydrocarbon production system 12), the on-site generation of exhaust gas 42, 60 may be particularly beneficial for the EOR system 18, due to its low oxygen content, high pressure, and heat derived from the SEGR gas turbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 may output or recirculate an exhaust gas 66 into the SEGR gas turbine system 52, while also routing the exhaust gas 42 to the EOR system 18 for use with the hydrocarbon production system 12. Likewise, the exhaust gas 42 may be extracted directly from the SEGR gas turbine system 52 (i.e., without passing through the EG processing system 54) for use in the EOR system 18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EG processing system 54. For example, the EGR system 58 includes one or more conduits, valves, blowers, exhaust gas treatment systems (e.g., filters, particulate removal units, gas separation units, gas purification units, heat exchangers, heat recovery units, moisture removal units, catalyst units, chemical injection units, or any combination thereof), and controls to recirculate the exhaust gas along an exhaust gas circulation path from an output (e.g., discharged exhaust gas 60) to an input (e.g., intake exhaust gas 66) of the SEGR gas turbine system 52. In the illustrated embodiment, the SEGR gas turbine system 52 intakes the exhaust gas 66 into a compressor section having one or more compressors, thereby compressing the exhaust gas 66 for use in a combustor section along with an intake of an oxidant 68 and one or more fuels 70. The oxidant 68 may include ambient air, pure oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any suitable oxidant that facilitates combustion of the fuel 70. The fuel 70 may include one or more gas fuels, liquid fuels, or any combination thereof. For example, the fuel 70 may include natural gas, liquefied natural gas (LNG), syngas, methane, ethane, propane, butane, naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or any combination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66, the oxidant 68, and the fuel 70 in the combustor section, thereby generating hot combustion gases or exhaust gas 60 to drive one or more turbine stages in a turbine section. In certain embodiments, each combustor in the combustor section includes one or more premix fuel nozzles, one or more diffusion fuel nozzles, or any combination thereof. For example, each premix fuel nozzle may be configured to mix the oxidant 68 and the fuel 70 internally within the fuel nozzle and/or partially upstream of the fuel nozzle, thereby injecting an oxidant-fuel mixture from the fuel nozzle into the combustion zone for a premixed combustion (e.g., a premixed flame). By further example, each diffusion fuel nozzle may be configured to isolate the flows of oxidant 68 and fuel 70 within the fuel nozzle, thereby separately injecting the oxidant 68 and the fuel 70 from the fuel nozzle into the combustion zone for diffusion combustion (e.g., a diffusion flame). In particular, the diffusion combustion provided by the diffusion fuel nozzles delays mixing of the oxidant 68 and the fuel 70 until the point of initial combustion, i.e., the flame region. In embodiments employing the diffusion fuel nozzles, the diffusion flame may provide increased flame stability, because the diffusion flame generally forms at the point of stoichiometry between the separate streams of oxidant 68 and fuel 70 (i.e., as the oxidant 68 and fuel 70 are mixing). In certain embodiments, one or more diluents (e.g., the exhaust gas 60, steam, nitrogen, or another inert gas) may be pre-mixed with the oxidant 68, the fuel 70, or both, in either the diffusion fuel nozzle or the premix fuel nozzle. In addition, one or more diluents (e.g., the exhaust gas 60, steam, nitrogen, or another inert gas) may be injected into the combustor at or downstream from the point of combustion within each combustor. The use of these diluents may help temper the flame (e.g., premix flame or diffusion flame), thereby helping to reduce NO_(X) emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂). Regardless of the type of flame, the combustion produces hot combustion gases or exhaust gas 60 to drive one or more turbine stages. As each turbine stage is driven by the exhaust gas 60, the SEGR gas turbine system 52 generates a mechanical power 72 and/or an electrical power 74 (e.g., via an electrical generator). The system 52 also outputs the exhaust gas 60, and may further output water 64. Again, the water 64 may be a treated water, such as a desalinated water, which may be useful in a variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52 using one or more extraction points 76. For example, the illustrated embodiment includes an exhaust gas (EG) supply system 78 having an exhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatment system 82, which receive exhaust gas 42 from the extraction points 76, treat the exhaust gas 42, and then supply or distribute the exhaust gas 42 to various target systems. The target systems may include the EOR system 18 and/or other systems, such as a pipeline 86, a storage tank 88, or a carbon sequestration system 90. The EG extraction system 80 may include one or more conduits, valves, controls, and flow separations, which facilitate isolation of the exhaust gas 42 from the oxidant 68, the fuel 70, and other contaminants, while also controlling the temperature, pressure, and flow rate of the extracted exhaust gas 42. The EG treatment system 82 may include one or more heat exchangers (e.g., heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (e.g., oxidation catalyst systems), particulate and/or water removal systems (e.g., gas dehydration units, inertial separators, coalescing filters, water impermeable filters, and other filters), chemical injection systems, solvent based treatment systems (e.g., absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and/or a solvent based treatment system, exhaust gas compressors, any combination thereof. These subsystems of the EG treatment system 82 enable control of the temperature, pressure, flow rate, moisture content (e.g., amount of water removal), particulate content (e.g., amount of particulate removal), and gas composition (e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of the EG treatment system 82, depending on the target system. For example, the EG treatment system 82 may direct all or part of the exhaust gas 42 through a carbon capture system, a gas separation system, a gas purification system, and/or a solvent based treatment system, which is controlled to separate and purify a carbonaceous gas (e.g., carbon dioxide) 92 and/or nitrogen (N₂) 94 for use in the various target systems. For example, embodiments of the EG treatment system 82 may perform gas separation and purification to produce a plurality of different streams 95 of exhaust gas 42, such as a first stream 96, a second stream 97, and a third stream 98. The first stream 96 may have a first composition that is rich in carbon dioxide and/or lean in nitrogen (e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have a second composition that has intermediate concentration levels of carbon dioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂ stream). The third stream 98 may have a third composition that is lean in carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ rich stream). Each stream 95 (e.g., 96, 97, and 98) may include a gas dehydration unit, a filter, a gas compressor, or any combination thereof, to facilitate delivery of the stream 95 to a target system. In certain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂ purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 percent by volume. In contrast, the CO₂ lean, N₂ rich stream 98 may have a CO₂ purity or concentration level of less than approximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 percent by volume, and an N₂ purity or concentration level of greater than approximately 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. The intermediate concentration CO₂, N₂ stream 97 may have a CO₂ purity or concentration level and/or a N₂ purity or concentration level of between approximately 30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent by volume. Although the foregoing ranges are merely non-limiting examples, the CO₂ rich, N₂ lean stream 96 and the CO₂ lean, N₂ rich stream 98 may be particularly well suited for use with the EOR system 18 and the other systems 84. However, any of these rich, lean, or intermediate concentration CO₂ streams 95 may be used, alone or in various combinations, with the EOR system 18 and the other systems 84. For example, the EOR system 18 and the other systems 84 (e.g., the pipeline 86, storage tank 88, and the carbon sequestration system 90) each may receive one or more CO₂ rich, N₂ lean streams 96, one or more CO₂ lean, N₂ rich streams 98, one or more intermediate concentration CO₂, N₂ streams 97, and one or more untreated exhaust gas 42 streams (i.e., bypassing the EG treatment system 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or more extraction points 76 along the compressor section, the combustor section, and/or the turbine section, such that the exhaust gas 42 may be used in the EOR system 18 and other systems 84 at suitable temperatures and pressures. The EG extraction system 80 and/or the EG treatment system 82 also may circulate fluid flows (e.g., exhaust gas 42) to and from the EG processing system 54. For example, a portion of the exhaust gas 42 passing through the EG processing system 54 may be extracted by the EG extraction system 80 for use in the EOR system 18 and the other systems 84. In certain embodiments, the EG supply system 78 and the EG processing system 54 may be independent or integral with one another, and thus may use independent or common subsystems. For example, the EG treatment system 82 may be used by both the EG supply system 78 and the EG processing system 54. Exhaust gas 42 extracted from the EG processing system 54 may undergo multiple stages of gas treatment, such as one or more stages of gas treatment in the EG processing system 54 followed by one or more additional stages of gas treatment in the EG treatment system 82.

At each extraction point 76, the extracted exhaust gas 42 may be substantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel or hydrocarbons) due to substantially stoichiometric combustion and/or gas treatment in the EG processing system 54. Furthermore, depending on the target system, the extracted exhaust gas 42 may undergo further treatment in the EG treatment system 82 of the EG supply system 78, thereby further reducing any residual oxidant 68, fuel 70, or other undesirable products of combustion. For example, either before or after treatment in the EG treatment system 82, the extracted exhaust gas 42 may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. By further example, either before or after treatment in the EG treatment system 82, the extracted exhaust gas 42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and other products of incomplete combustion. Thus, the exhaust gas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables the exhaust extraction at a multitude of locations 76. For example, the compressor section of the system 52 may be used to compress the exhaust gas 66 without any oxidant 68 (i.e., only compression of the exhaust gas 66), such that a substantially oxygen-free exhaust gas 42 may be extracted from the compressor section and/or the combustor section prior to entry of the oxidant 68 and the fuel 70. The extraction points 76 may be located at interstage ports between adjacent compressor stages, at ports along the compressor discharge casing, at ports along each combustor in the combustor section, or any combination thereof. In certain embodiments, the exhaust gas 66 may not mix with the oxidant 68 and fuel 70 until it reaches the head end portion and/or fuel nozzles of each combustor in the combustor section. Furthermore, one or more flow separators (e.g., walls, dividers, baffles, or the like) may be used to isolate the oxidant 68 and the fuel 70 from the extraction points 76. With these flow separators, the extraction points 76 may be disposed directly along a wall of each combustor in the combustor section.

Once the exhaust gas 66, oxidant 68, and fuel 70 flow through the head end portion (e.g., through fuel nozzles) into the combustion portion (e.g., combustion chamber) of each combustor, the SEGR gas turbine system 52 is controlled to provide a substantially stoichiometric combustion of the exhaust gas 66, oxidant 68, and fuel 70. For example, the system 52 may maintain an equivalence ratio of approximately 0.95 to approximately 1.05. As a result, the products of combustion of the mixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor is substantially free of oxygen and unburnt fuel. Thus, the products of combustion (or exhaust gas) may be extracted from the turbine section of the SEGR gas turbine system 52 for use as the exhaust gas 42 routed to the EOR system 18. Along the turbine section, the extraction points 76 may be located at any turbine stage, such as interstage ports between adjacent turbine stages. Thus, using any of the foregoing extraction points 76, the turbine-based service system 14 may generate, extract, and deliver the exhaust gas 42 to the hydrocarbon production system 12 (e.g., the EOR system 18) for use in the production of oil/gas 48 from the subterranean reservoir 20.

FIG. 2 is a diagram of an embodiment of the system 10 of FIG. 1, illustrating a control system 100 coupled to the turbine-based service system 14 and the hydrocarbon production system 12. In the illustrated embodiment, the turbine-based service system 14 includes a combined cycle system 102, which includes the SEGR gas turbine system 52 as a topping cycle, a steam turbine 104 as a bottoming cycle, and the HRSG 56 to recover heat from the exhaust gas 60 to generate the steam 62 for driving the steam turbine 104. Again, the SEGR gas turbine system 52 receives, mixes, and stoichiometrically combusts the exhaust gas 66, the oxidant 68, and the fuel 70 (e.g., premix and/or diffusion flames), thereby producing the exhaust gas 60, the mechanical power 72, the electrical power 74, and/or the water 64. For example, the SEGR gas turbine system 52 may drive one or more loads or machinery 106, such as an electrical generator, an oxidant compressor (e.g., a main air compressor), a gear box, a pump, equipment of the hydrocarbon production system 12, or any combination thereof. In some embodiments, the machinery 106 may include other drives, such as electrical motors or steam turbines (e.g., the steam turbine 104), in tandem with the SEGR gas turbine system 52. Accordingly, an output of the machinery 106 driven by the SEGR gas turbines system 52 (and any additional drives) may include the mechanical power 72 and the electrical power 74. The mechanical power 72 and/or the electrical power 74 may be used on-site for powering the hydrocarbon production system 12, the electrical power 74 may be distributed to the power grid, or any combination thereof. The output of the machinery 106 also may include a compressed fluid, such as a compressed oxidant 68 (e.g., air or oxygen), for intake into the combustion section of the SEGR gas turbine system 52. Each of these outputs (e.g., the exhaust gas 60, the mechanical power 72, the electrical power 74, and/or the water 64) may be considered a service of the turbine-based service system 14.

The SEGR gas turbine system 52 produces the exhaust gas 42, 60, which may be substantially free of oxygen, and routes this exhaust gas 42, 60 to the EG processing system 54 and/or the EG supply system 78. The EG supply system 78 may treat and delivery the exhaust gas 42 (e.g., streams 95) to the hydrocarbon production system 12 and/or the other systems 84. As discussed above, the EG processing system 54 may include the HRSG 56 and the EGR system 58. The HRSG 56 may include one or more heat exchangers, condensers, and various heat recovery equipment, which may be used to recover or transfer heat from the exhaust gas 60 to water 108 to generate the steam 62 for driving the steam turbine 104. Similar to the SEGR gas turbine system 52, the steam turbine 104 may drive one or more loads or machinery 106, thereby generating the mechanical power 72 and the electrical power 74. In the illustrated embodiment, the SEGR gas turbine system 52 and the steam turbine 104 are arranged in tandem to drive the same machinery 106. However, in other embodiments, the SEGR gas turbine system 52 and the steam turbine 104 may separately drive different machinery 106 to independently generate mechanical power 72 and/or electrical power 74. As the steam turbine 104 is driven by the steam 62 from the HRSG 56, the steam 62 gradually decreases in temperature and pressure. Accordingly, the steam turbine 104 recirculates the used steam 62 and/or water 108 back into the HRSG 56 for additional steam generation via heat recovery from the exhaust gas 60. In addition to steam generation, the HRSG 56, the EGR system 58, and/or another portion of the EG processing system 54 may produce the water 64, the exhaust gas 42 for use with the hydrocarbon production system 12, and the exhaust gas 66 for use as an input into the SEGR gas turbine system 52. For example, the water 64 may be a treated water 64, such as a desalinated water for use in other applications. The desalinated water may be particularly useful in regions of low water availability. Regarding the exhaust gas 60, embodiments of the EG processing system 54 may be configured to recirculate the exhaust gas 60 through the EGR system 58 with or without passing the exhaust gas 60 through the HRSG 56.

In the illustrated embodiment, the SEGR gas turbine system 52 has an exhaust recirculation path 110, which extends from an exhaust outlet to an exhaust inlet of the system 52. Along the path 110, the exhaust gas 60 passes through the EG processing system 54, which includes the HRSG 56 and the EGR system 58 in the illustrated embodiment. The EGR system 58 may include one or more conduits, valves, blowers, gas treatment systems (e.g., filters, particulate removal units, gas separation units, gas purification units, heat exchangers, heat recovery units such as heat recovery steam generators, moisture removal units, catalyst units, chemical injection units, or any combination thereof) in series and/or parallel arrangements along the path 110. In other words, the EGR system 58 may include any flow control components, pressure control components, temperature control components, moisture control components, and gas composition control components along the exhaust recirculation path 110 between the exhaust outlet and the exhaust inlet of the system 52. Accordingly, in embodiments with the HRSG 56 along the path 110, the HRSG 56 may be considered a component of the EGR system 58. However, in certain embodiments, the HRSG 56 may be disposed along an exhaust path independent from the exhaust recirculation path 110. Regardless of whether the HRSG 56 is along a separate path or a common path with the EGR system 58, the HRSG 56 and the EGR system 58 intake the exhaust gas 60 and output either the recirculated exhaust gas 66, the exhaust gas 42 for use with the EG supply system 78 (e.g., for the hydrocarbon production system 12 and/or other systems 84), or another output of exhaust gas. Again, the SEGR gas turbine system 52 intakes, mixes, and stoichiometrically combusts the exhaust gas 66, the oxidant 68, and the fuel 70 (e.g., premixed and/or diffusion flames) to produce a substantially oxygen-free and fuel-free exhaust gas 60 for distribution to the EG processing system 54, the hydrocarbon production system 12, or other systems 84.

As noted above with reference to FIG. 1, the hydrocarbon production system 12 may include a variety of equipment to facilitate the recovery or production of oil/gas 48 from a subterranean reservoir 20 through an oil/gas well 26. For example, the hydrocarbon production system 12 may include the EOR system 18 having the fluid injection system 34. In the illustrated embodiment, the fluid injection system 34 includes an exhaust gas injection EOR system 112 and a steam injection EOR system 114. Although the fluid injection system 34 may receive fluids from a variety of sources, the illustrated embodiment may receive the exhaust gas 42 and the steam 62 from the turbine-based service system 14. The exhaust gas 42 and/or the steam 62 produced by the turbine-based service system 14 also may be routed to the hydrocarbon production system 12 for use in other oil/gas systems 116.

The quantity, quality, and flow of the exhaust gas 42 and/or the steam 62 may be controlled by the control system 100. The control system 100 may be dedicated entirely to the turbine-based service system 14, or the control system 100 may optionally also provide control (or at least some data to facilitate control) for the hydrocarbon production system 12 and/or other systems 84. In the illustrated embodiment, the control system 100 includes a controller 118 having a processor 120, a memory 122, a steam turbine control 124, a SEGR gas turbine system control 126, and a machinery control 128. The processor 120 may include a single processor or two or more redundant processors, such as triple redundant processors for control of the turbine-based service system 14. The memory 122 may include volatile and/or non-volatile memory. For example, the memory 122 may include one or more hard drives, flash memory, read-only memory, random access memory, or any combination thereof. The controls 124, 126, and 128 may include software and/or hardware controls. For example, the controls 124, 126, and 128 may include various instructions or code stored on the memory 122 and executable by the processor 120. The control 124 is configured to control operation of the steam turbine 104, the SEGR gas turbine system control 126 is configured to control the system 52, and the machinery control 128 is configured to control the machinery 106. Thus, the controller 118 (e.g., controls 124, 126, and 128) may be configured to coordinate various sub-systems of the turbine-based service system 14 to provide a suitable stream of the exhaust gas 42 to the hydrocarbon production system 12.

In certain embodiments of the control system 100, each element (e.g., system, subsystem, and component) illustrated in the drawings or described herein includes (e.g., directly within, upstream, or downstream of such element) one or more industrial control features, such as sensors and control devices, which are communicatively coupled with one another over an industrial control network along with the controller 118. For example, the control devices associated with each element may include a dedicated device controller (e.g., including a processor, memory, and control instructions), one or more actuators, valves, switches, and industrial control equipment, which enable control based on sensor feedback 130, control signals from the controller 118, control signals from a user, or any combination thereof. Thus, any of the control functionality described herein may be implemented with control instructions stored and/or executable by the controller 118, dedicated device controllers associated with each element, or a combination thereof.

In order to facilitate such control functionality, the control system 100 includes one or more sensors distributed throughout the system 10 to obtain the sensor feedback 130 for use in execution of the various controls, e.g., the controls 124, 126, and 128. For example, the sensor feedback 130 may be obtained from sensors distributed throughout the SEGR gas turbine system 52, the machinery 106, the EG processing system 54, the steam turbine 104, the hydrocarbon production system 12, or any other components throughout the turbine-based service system 14 or the hydrocarbon production system 12. For example, the sensor feedback 130 may include temperature feedback, pressure feedback, flow rate feedback, flame temperature feedback, combustion dynamics feedback, intake oxidant composition feedback, intake fuel composition feedback, exhaust composition feedback, the output level of mechanical power 72, the output level of electrical power 74, the output quantity of the exhaust gas 42, 60, the output quantity or quality of the water 64, or any combination thereof. For example, the sensor feedback 130 may include a composition of the exhaust gas 42, 60 to facilitate stoichiometric combustion in the SEGR gas turbine system 52. For example, the sensor feedback 130 may include feedback from one or more intake oxidant sensors along an oxidant supply path of the oxidant 68, one or more intake fuel sensors along a fuel supply path of the fuel 70, and one or more exhaust emissions sensors disposed along the exhaust recirculation path 110 and/or within the SEGR gas turbine system 52. The intake oxidant sensors, intake fuel sensors, and exhaust emissions sensors may include temperature sensors, pressure sensors, flow rate sensors, and composition sensors. The emissions sensors may includes sensors for nitrogen oxides (e.g., NO_(X) sensors), carbon oxides (e.g., CO sensors and CO₂ sensors), sulfur oxides (e.g., SO_(X) sensors), hydrogen (e.g., H₂ sensors), oxygen (e.g., O₂ sensors), unburnt hydrocarbons (e.g., HC sensors), or other products of incomplete combustion, or any combination thereof.

Using this feedback 130, the control system 100 may adjust (e.g., increase, decrease, or maintain) the intake flow of exhaust gas 66, oxidant 68, and/or fuel 70 into the SEGR gas turbine system 52 (among other operational parameters) to maintain the equivalence ratio within a suitable range, e.g., between approximately 0.95 to approximately 1.05, between approximately 0.95 to approximately 1.0, between approximately 1.0 to approximately 1.05, or substantially at 1.0. For example, the control system 100 may analyze the feedback 130 to monitor the exhaust emissions (e.g., concentration levels of nitrogen oxides, carbon oxides such as CO and CO₂, sulfur oxides, hydrogen, oxygen, unburnt hydrocarbons, and other products of incomplete combustion) and/or determine the equivalence ratio, and then control one or more components to adjust the exhaust emissions (e.g., concentration levels in the exhaust gas 42) and/or the equivalence ratio. The controlled components may include any of the components illustrated and described with reference to the drawings, including but not limited to, valves along the supply paths for the oxidant 68, the fuel 70, and the exhaust gas 66; an oxidant compressor, a fuel pump, or any components in the EG processing system 54; any components of the SEGR gas turbine system 52, or any combination thereof. The controlled components may adjust (e.g., increase, decrease, or maintain) the flow rates, temperatures, pressures, or percentages (e.g., equivalence ratio) of the oxidant 68, the fuel 70, and the exhaust gas 66 that combust within the SEGR gas turbine system 52. The controlled components also may include one or more gas treatment systems, such as catalyst units (e.g., oxidation catalyst units), supplies for the catalyst units (e.g., oxidation fuel, heat, electricity, etc.), gas purification and/or separation units (e.g., solvent based separators, absorbers, flash tanks, etc.), and filtration units. The gas treatment systems may help reduce various exhaust emissions along the exhaust recirculation path 110, a vent path (e.g., exhausted into the atmosphere), or an extraction path to the EG supply system 78.

In certain embodiments, the control system 100 may analyze the feedback 130 and control one or more components to maintain or reduce emissions levels (e.g., concentration levels in the exhaust gas 42, 60, 95) to a target range, such as less than approximately 10, 20, 30, 40, 50, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts per million by volume (ppmv). These target ranges may be the same or different for each of the exhaust emissions, e.g., concentration levels of nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen, unburnt hydrocarbons, and other products of incomplete combustion. For example, depending on the equivalence ratio, the control system 100 may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv; carbon monoxide (CO) within a target range of less than approximately 20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides (NO_(X)) within a target range of less than approximately 50, 100, 200, 300, 400, or 500 ppmv. In certain embodiments operating with a substantially stoichiometric equivalence ratio, the control system 100 may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; and carbon monoxide (CO) within a target range of less than approximately 500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodiments operating with a fuel-lean equivalence ratio (e.g., between approximately 0.95 to 1.0), the control system 100 may selectively control exhaust emissions (e.g., concentration levels) of oxidant (e.g., oxygen) within a target range of less than approximately 500, 600, 700, 800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide (CO) within a target range of less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g., NO_(X)) within a target range of less than approximately 50, 100, 150, 200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merely examples, and are not intended to limit the scope of the disclosed embodiments.

The control system 100 also may be coupled to a local interface 132 and a remote interface 134. For example, the local interface 132 may include a computer workstation disposed on-site at the turbine-based service system 14 and/or the hydrocarbon production system 12. In contrast, the remote interface 134 may include a computer workstation disposed off-site from the turbine-based service system 14 and the hydrocarbon production system 12, such as through an internet connection. These interfaces 132 and 134 facilitate monitoring and control of the turbine-based service system 14, such as through one or more graphical displays of sensor feedback 130, operational parameters, and so forth.

Again, as noted above, the controller 118 includes a variety of controls 124, 126, and 128 to facilitate control of the turbine-based service system 14. The steam turbine control 124 may receive the sensor feedback 130 and output control commands to facilitate operation of the steam turbine 104. For example, the steam turbine control 124 may receive the sensor feedback 130 from the HRSG 56, the machinery 106, temperature and pressure sensors along a path of the steam 62, temperature and pressure sensors along a path of the water 108, and various sensors indicative of the mechanical power 72 and the electrical power 74. Likewise, the SEGR gas turbine system control 126 may receive sensor feedback 130 from one or more sensors disposed along the SEGR gas turbine system 52, the machinery 106, the EG processing system 54, or any combination thereof. For example, the sensor feedback 130 may be obtained from temperature sensors, pressure sensors, clearance sensors, vibration sensors, flame sensors, fuel composition sensors, exhaust gas composition sensors, or any combination thereof, disposed within or external to the SEGR gas turbine system 52. Finally, the machinery control 128 may receive sensor feedback 130 from various sensors associated with the mechanical power 72 and the electrical power 74, as well as sensors disposed within the machinery 106. Each of these controls 124, 126, and 128 uses the sensor feedback 130 to improve operation of the turbine-based service system 14.

In the illustrated embodiment, the SEGR gas turbine system control 126 may execute instructions to control the quantity and quality of the exhaust gas 42, 60, 95 in the EG processing system 54, the EG supply system 78, the hydrocarbon production system 12, and/or the other systems 84. For example, the SEGR gas turbine system control 126 may maintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in the exhaust gas 60 below a threshold suitable for use with the exhaust gas injection EOR system 112. In certain embodiments, the threshold levels may be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen) and/or unburnt fuel by volume of the exhaust gas 42, 60; or the threshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (and other exhaust emissions) may be less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts per million by volume (ppmv) in the exhaust gas 42, 60. By further example, in order to achieve these low levels of oxidant (e.g., oxygen) and/or unburnt fuel, the SEGR gas turbine system control 126 may maintain an equivalence ratio for combustion in the SEGR gas turbine system 52 between approximately 0.95 and approximately 1.05. The SEGR gas turbine system control 126 also may control the EG extraction system 80 and the EG treatment system 82 to maintain the temperature, pressure, flow rate, and gas composition of the exhaust gas 42, 60, 95 within suitable ranges for the exhaust gas injection EOR system 112, the pipeline 86, the storage tank 88, and the carbon sequestration system 90. As discussed above, the EG treatment system 82 may be controlled to purify and/or separate the exhaust gas 42 into one or more gas streams 95, such as the CO₂ rich, N₂ lean stream 96, the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. In addition to controls for the exhaust gas 42, 60, and 95, the controls 124, 126, and 128 may execute one or more instructions to maintain the mechanical power 72 within a suitable power range, or maintain the electrical power 74 within a suitable frequency and power range.

FIG. 3 is a diagram of embodiment of the system 10, further illustrating details of the SEGR gas turbine system 52 for use with the hydrocarbon production system 12 and/or other systems 84. In the illustrated embodiment, the SEGR gas turbine system 52 includes a gas turbine engine 150 coupled to the EG processing system 54. The illustrated gas turbine engine 150 includes a compressor section 152, a combustor section 154, and an expander section or turbine section 156. The compressor section 152 includes one or more exhaust gas compressors or compressor stages 158, such as 1 to 20 stages of rotary compressor blades disposed in a series arrangement. Likewise, the combustor section 154 includes one or more combustors 160, such as 1 to 20 combustors 160 distributed circumferentially about a rotational axis 162 of the SEGR gas turbine system 52. Furthermore, each combustor 160 may include one or more fuel nozzles 164 configured to inject the exhaust gas 66, the oxidant 68, and/or the fuel 70. For example, a head end portion 166 of each combustor 160 may house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164, which may inject streams or mixtures of the exhaust gas 66, the oxidant 68, and/or the fuel 70 into a combustion portion 168 (e.g., combustion chamber) of the combustor 160.

The fuel nozzles 164 may include any combination of premix fuel nozzles 164 (e.g., configured to premix the oxidant 68 and fuel 70 for generation of an oxidant/fuel premix flame) and/or diffusion fuel nozzles 164 (e.g., configured to inject separate flows of the oxidant 68 and fuel 70 for generation of an oxidant/fuel diffusion flame). Embodiments of the premix fuel nozzles 164 may include swirl vanes, mixing chambers, or other features to internally mix the oxidant 68 and fuel 70 within the nozzles 164, prior to injection and combustion in the combustion chamber 168. The premix fuel nozzles 164 also may receive at least some partially mixed oxidant 68 and fuel 70. In certain embodiments, each diffusion fuel nozzle 164 may isolate flows of the oxidant 68 and the fuel 70 until the point of injection, while also isolating flows of one or more diluents (e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) until the point of injection. In other embodiments, each diffusion fuel nozzle 164 may isolate flows of the oxidant 68 and the fuel 70 until the point of injection, while partially mixing one or more diluents (e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) with the oxidant 68 and/or the fuel 70 prior to the point of injection. In addition, one or more diluents (e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) may be injected into the combustor (e.g., into the hot products of combustion) either at or downstream from the combustion zone, thereby helping to reduce the temperature of the hot products of combustion and reduce emissions of NO_(X) (e.g., NO and NO₂). Regardless of the type of fuel nozzle 164, the SEGR gas turbine system 52 may be controlled to provide substantially stoichiometric combustion of the oxidant 68 and fuel 70.

In diffusion combustion embodiments using the diffusion fuel nozzles 164, the fuel 70 and oxidant 68 generally do not mix upstream from the diffusion flame, but rather the fuel 70 and oxidant 68 mix and react directly at the flame surface and/or the flame surface exists at the location of mixing between the fuel 70 and oxidant 68. In particular, the fuel 70 and oxidant 68 separately approach the flame surface (or diffusion boundary/interface), and then diffuse (e.g., via molecular and viscous diffusion) along the flame surface (or diffusion boundary/interface) to generate the diffusion flame. It is noteworthy that the fuel 70 and oxidant 68 may be at a substantially stoichiometric ratio along this flame surface (or diffusion boundary/interface), which may result in a greater flame temperature (e.g., a peak flame temperature) along this flame surface. The stoichiometric fuel/oxidant ratio generally results in a greater flame temperature (e.g., a peak flame temperature), as compared with a fuel-lean or fuel-rich fuel/oxidant ratio. As a result, the diffusion flame may be substantially more stable than a premix flame, because the diffusion of fuel 70 and oxidant 68 helps to maintain a stoichiometric ratio (and greater temperature) along the flame surface. Although greater flame temperatures can also lead to greater exhaust emissions, such as NO_(X) emissions, the disclosed embodiments use one or more diluents to help control the temperature and emissions while still avoiding any premixing of the fuel 70 and oxidant 68. For example, the disclosed embodiments may introduce one or more diluents separate from the fuel 70 and oxidant 68 (e.g., after the point of combustion and/or downstream from the diffusion flame), thereby helping to reduce the temperature and reduce the emissions (e.g., NO_(X) emissions) produced by the diffusion flame.

In operation, as illustrated, the compressor section 152 receives and compresses the exhaust gas 66 from the EG processing system 54, and outputs a compressed exhaust gas 170 to each of the combustors 160 in the combustor section 154. Upon combustion of the fuel 60, oxidant 68, and exhaust gas 170 within each combustor 160, additional exhaust gas or products of combustion 172 (i.e., combustion gas) is routed into the turbine section 156. Similar to the compressor section 152, the turbine section 156 includes one or more turbines or turbine stages 174, which may include a series of rotary turbine blades. These turbine blades are then driven by the products of combustion 172 generated in the combustor section 154, thereby driving rotation of a shaft 176 coupled to the machinery 106. Again, the machinery 106 may include a variety of equipment coupled to either end of the SEGR gas turbine system 52, such as machinery 106, 178 coupled to the turbine section 156 and/or machinery 106, 180 coupled to the compressor section 152. In certain embodiments, the machinery 106, 178, 180 may include one or more electrical generators, oxidant compressors for the oxidant 68, fuel pumps for the fuel 70, gear boxes, or additional drives (e.g., steam turbine 104, electrical motor, etc.) coupled to the SEGR gas turbine system 52. Non-limiting examples are discussed in further detail below with reference to TABLE 1. As illustrated, the turbine section 156 outputs the exhaust gas 60 to recirculate along the exhaust recirculation path 110 from an exhaust outlet 182 of the turbine section 156 to an exhaust inlet 184 into the compressor section 152. Along the exhaust recirculation path 110, the exhaust gas 60 passes through the EG processing system 54 (e.g., the HRSG 56 and/or the EGR system 58) as discussed in detail above.

Again, each combustor 160 in the combustor section 154 receives, mixes, and stoichiometrically combusts the compressed exhaust gas 170, the oxidant 68, and the fuel 70 to produce the additional exhaust gas or products of combustion 172 to drive the turbine section 156. In certain embodiments, the oxidant 68 is compressed by an oxidant compression system 186, such as a main oxidant compression (MOC) system (e.g., a main air compression (MAC) system) having one or more oxidant compressors (MOCs). The oxidant compression system 186 includes an oxidant compressor 188 coupled to a drive 190. For example, the drive 190 may include an electric motor, a combustion engine, or any combination thereof. In certain embodiments, the drive 190 may be a turbine engine, such as the gas turbine engine 150. Accordingly, the oxidant compression system 186 may be an integral part of the machinery 106. In other words, the compressor 188 may be directly or indirectly driven by the mechanical power 72 supplied by the shaft 176 of the gas turbine engine 150. In such an embodiment, the drive 190 may be excluded, because the compressor 188 relies on the power output from the turbine engine 150. However, in certain embodiments employing more than one oxidant compressor is employed, a first oxidant compressor (e.g., a low pressure (LP) oxidant compressor) may be driven by the drive 190 while the shaft 176 drives a second oxidant compressor (e.g., a high pressure (HP) oxidant compressor), or vice versa. For example, in another embodiment, the HP MOC is driven by the drive 190 and the LP oxidant compressor is driven by the shaft 176. In the illustrated embodiment, the oxidant compression system 186 is separate from the machinery 106. In each of these embodiments, the compression system 186 compresses and supplies the oxidant 68 to the fuel nozzles 164 and the combustors 160. Accordingly, some or all of the machinery 106, 178, 180 may be configured to increase the operational efficiency of the compression system 186 (e.g., the compressor 188 and/or additional compressors).

The variety of components of the machinery 106, indicated by element numbers 106A, 106B, 106C, 106D, 106E, and 106F, may be disposed along the line of the shaft 176 and/or parallel to the line of the shaft 176 in one or more series arrangements, parallel arrangements, or any combination of series and parallel arrangements. For example, the machinery 106, 178, 180 (e.g., 106A through 106F) may include any series and/or parallel arrangement, in any order, of: one or more gearboxes (e.g., parallel shaft, epicyclic gearboxes), one or more compressors (e.g., oxidant compressors, booster compressors such as EG booster compressors), one or more power generation units (e.g., electrical generators), one or more drives (e.g., steam turbine engines, electrical motors), heat exchange units (e.g., direct or indirect heat exchangers), clutches, or any combination thereof. The compressors may include axial compressors, radial or centrifugal compressors, or any combination thereof, each having one or more compression stages. Regarding the heat exchangers, direct heat exchangers may include spray coolers (e.g., spray intercoolers), which inject a liquid spray into a gas flow (e.g., oxidant flow) for direct cooling of the gas flow. Indirect heat exchangers may include at least one wall (e.g., a shell and tube heat exchanger) separating first and second flows, such as a fluid flow (e.g., oxidant flow) separated from a coolant flow (e.g., water, air, refrigerant, or any other liquid or gas coolant), wherein the coolant flow transfers heat from the fluid flow without any direct contact. Examples of indirect heat exchangers include intercooler heat exchangers and heat recovery units, such as heat recovery steam generators. The heat exchangers also may include heaters. As discussed in further detail below, each of these machinery components may be used in various combinations as indicated by the non-limiting examples set forth in TABLE 1.

Generally, the machinery 106, 178, 180 may be configured to increase the efficiency of the compression system 186 by, for example, adjusting operational speeds of one or more oxidant compressors in the system 186, facilitating compression of the oxidant 68 through cooling, and/or extraction of surplus power. The disclosed embodiments are intended to include any and all permutations of the foregoing components in the machinery 106, 178, 180 in series and parallel arrangements, wherein one, more than one, all, or none of the components derive power from the shaft 176. As illustrated below, TABLE 1 depicts some non-limiting examples of arrangements of the machinery 106, 178, 180 disposed proximate and/or coupled to the compressor and turbine sections 152, 156.

TABLE 1 106A 106B 106C 106D 106E 106F MOC GEN MOC GBX GEN LP HP GEN MOC MOC HP GBX LP GEN MOC MOC MOC GBX GEN MOC HP GBX GEN LP MOC MOC MOC GBX GEN MOC GBX DRV DRV GBX LP HP GBX GEN MOC MOC DRV GBX HP LP GEN MOC MOC HP GBX LP GEN MOC CLR MOC HP GBX LP GBX GEN MOC CLR MOC HP GBX LP GEN MOC HTR MOC STGN MOC GEN DRV MOC DRV GEN DRV MOC GEN DRV CLU MOC GEN DRV CLU MOC GBX GEN

As illustrated above in TABLE 1, a cooling unit is represented as CLR, a clutch is represented as CLU, a drive is represented by DRV, a gearbox is represented as GBX, a generator is represented by GEN, a heating unit is represented by HTR, a main oxidant compressor unit is represented by MOC, with low pressure and high pressure variants being represented as LP MOC and HP MOC, respectively, and a steam generator unit is represented as STGN. Although TABLE 1 illustrates the machinery 106, 178, 180 in sequence toward the compressor section 152 or the turbine section 156, TABLE 1 is also intended to cover the reverse sequence of the machinery 106, 178, 180. In TABLE 1, any cell including two or more components is intended to cover a parallel arrangement of the components. TABLE 1 is not intended to exclude any non-illustrated permutations of the machinery 106, 178, 180. These components of the machinery 106, 178, 180 may enable feedback control of temperature, pressure, and flow rate of the oxidant 68 sent to the gas turbine engine 150. As discussed in further detail below, the oxidant 68 and the fuel 70 may be supplied to the gas turbine engine 150 at locations specifically selected to facilitate isolation and extraction of the compressed exhaust gas 170 without any oxidant 68 or fuel 70 degrading the quality of the exhaust gas 170.

The EG supply system 78, as illustrated in FIG. 3, is disposed between the gas turbine engine 150 and the target systems (e.g., the hydrocarbon production system 12 and the other systems 84). In particular, the EG supply system 78, e.g., the EG extraction system (EGES) 80), may be coupled to the gas turbine engine 150 at one or more extraction points 76 along the compressor section 152, the combustor section 154, and/or the turbine section 156. For example, the extraction points 76 may be located between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76 between compressor stages. Each of these interstage extraction points 76 provides a different temperature and pressure of the extracted exhaust gas 42. Similarly, the extraction points 76 may be located between adjacent turbine stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76 between turbine stages. Each of these interstage extraction points 76 provides a different temperature and pressure of the extracted exhaust gas 42. By further example, the extraction points 76 may be located at a multitude of locations throughout the combustor section 154, which may provide different temperatures, pressures, flow rates, and gas compositions. Each of these extraction points 76 may include an EG extraction conduit, one or more valves, sensors, and controls, which may be used to selectively control the flow of the extracted exhaust gas 42 to the EG supply system 78.

The extracted exhaust gas 42, which is distributed by the EG supply system 78, has a controlled composition suitable for the target systems (e.g., the hydrocarbon production system 12 and the other systems 84). For example, at each of these extraction points 76, the exhaust gas 170 may be substantially isolated from injection points (or flows) of the oxidant 68 and the fuel 70. In other words, the EG supply system 78 may be specifically designed to extract the exhaust gas 170 from the gas turbine engine 150 without any added oxidant 68 or fuel 70. Furthermore, in view of the stoichiometric combustion in each of the combustors 160, the extracted exhaust gas 42 may be substantially free of oxygen and fuel. The EG supply system 78 may route the extracted exhaust gas 42 directly or indirectly to the hydrocarbon production system 12 and/or other systems 84 for use in various processes, such as enhanced oil recovery, carbon sequestration, storage, or transport to an offsite location. However, in certain embodiments, the EG supply system 78 includes the EG treatment system (EGTS) 82 for further treatment of the exhaust gas 42, prior to use with the target systems. For example, the EG treatment system 82 may purify and/or separate the exhaust gas 42 into one or more streams 95, such as the CO₂ rich, N₂ lean stream 96, the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. These treated exhaust gas streams 95 may be used individually, or in any combination, with the hydrocarbon production system 12 and the other systems 84 (e.g., the pipeline 86, the storage tank 88, and the carbon sequestration system 90).

Similar to the exhaust gas treatments performed in the EG supply system 78, the EG processing system 54 may include a plurality of exhaust gas (EG) treatment components 192, such as indicated by element numbers 194, 196, 198, 200, 202, 204, 206, 208, and 210. These EG treatment components 192 (e.g., 194 through 210) may be disposed along the exhaust recirculation path 110 in one or more series arrangements, parallel arrangements, or any combination of series and parallel arrangements. For example, the EG treatment components 192 (e.g., 194 through 210) may include any series and/or parallel arrangement, in any order, of: one or more heat exchangers (e.g., heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (e.g., oxidation catalyst systems), particulate and/or water removal systems (e.g., inertial separators, coalescing filters, water impermeable filters, and other filters), chemical injection systems, solvent based treatment systems (e.g., absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and/or a solvent based treatment system, or any combination thereof. In certain embodiments, the catalyst systems may include an oxidation catalyst, a carbon monoxide reduction catalyst, a nitrogen oxides reduction catalyst, an aluminum oxide, a zirconium oxide, a silicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, a cobalt oxide, or a mixed metal oxide, or a combination thereof. The disclosed embodiments are intended to include any and all permutations of the foregoing components 192 in series and parallel arrangements. As illustrated below, TABLE 2 depicts some non-limiting examples of arrangements of the components 192 along the exhaust recirculation path 110.

TABLE 2 194 196 198 200 202 204 206 208 210 CU HRU BB MRU PRU CU HRU HRU BB MRU PRU DIL CU HRSG HRSG BB MRU PRU OCU HRU OCU HRU OCU BB MRU PRU HRU HRU BB MRU PRU CU CU HRSG HRSG BB MRU PRU DIL OCU OCU OCU HRSG OCU HRSG OCU BB MRU PRU DIL OCU OCU OCU HRSG HRSG BB COND INER WFIL CFIL DIL ST ST OCU OCU BB COND INER FIL DIL HRSG HRSG ST ST OCU HRSG HRSG OCU BB MRU MRU PRU PRU ST ST HE WFIL INER FIL COND CFIL CU HRU HRU HRU BB MRU PRU PRU DIL COND COND COND HE INER FIL COND CFIL WFIL

As illustrated above in TABLE 2, a catalyst unit is represented by CU, an oxidation catalyst unit is represented by OCU, a booster blower is represented by BB, a heat exchanger is represented by HX, a heat recovery unit is represented by HRU, a heat recovery steam generator is represented by HRSG, a condenser is represented by COND, a steam turbine is represented by ST, a particulate removal unit is represented by PRU, a moisture removal unit is represented by MRU, a filter is represented by FIL, a coalescing filter is represented by CFIL, a water impermeable filter is represented by WFIL, an inertial separator is represented by INER, and a diluent supply system (e.g., steam, nitrogen, or other inert gas) is represented by DIL. Although TABLE 2 illustrates the components 192 in sequence from the exhaust outlet 182 of the turbine section 156 toward the exhaust inlet 184 of the compressor section 152, TABLE 2 is also intended to cover the reverse sequence of the illustrated components 192. In TABLE 2, any cell including two or more components is intended to cover an integrated unit with the components, a parallel arrangement of the components, or any combination thereof. Furthermore, in context of TABLE 2, the HRU, the HRSG, and the COND are examples of the HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL are examples of the WRU; the INER, FIL, WFIL, and CFIL are examples of the PRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 is not intended to exclude any non-illustrated permutations of the components 192. In certain embodiments, the illustrated components 192 (e.g., 194 through 210) may be partially or completed integrated within the HRSG 56, the EGR system 58, or any combination thereof. These EG treatment components 192 may enable feedback control of temperature, pressure, flow rate, and gas composition, while also removing moisture and particulates from the exhaust gas 60. Furthermore, the treated exhaust gas 60 may be extracted at one or more extraction points 76 for use in the EG supply system 78 and/or recirculated to the exhaust inlet 184 of the compressor section 152.

As the treated, recirculated exhaust gas 66 passes through the compressor section 152, the SEGR gas turbine system 52 may bleed off a portion of the compressed exhaust gas along one or more lines 212 (e.g., bleed conduits or bypass conduits). Each line 212 may route the exhaust gas into one or more heat exchangers 214 (e.g., cooling units), thereby cooling the exhaust gas for recirculation back into the SEGR gas turbine system 52. For example, after passing through the heat exchanger 214, a portion of the cooled exhaust gas may be routed to the turbine section 156 along line 212 for cooling and/or sealing of the turbine casing, turbine shrouds, bearings, and other components. In such an embodiment, the SEGR gas turbine system 52 does not route any oxidant 68 (or other potential contaminants) through the turbine section 156 for cooling and/or sealing purposes, and thus any leakage of the cooled exhaust gas will not contaminate the hot products of combustion (e.g., working exhaust gas) flowing through and driving the turbine stages of the turbine section 156. By further example, after passing through the heat exchanger 214, a portion of the cooled exhaust gas may be routed along line 216 (e.g., return conduit) to an upstream compressor stage of the compressor section 152, thereby improving the efficiency of compression by the compressor section 152. In such an embodiment, the heat exchanger 214 may be configured as an interstage cooling unit for the compressor section 152. In this manner, the cooled exhaust gas helps to increase the operational efficiency of the SEGR gas turbine system 52, while simultaneously helping to maintain the purity of the exhaust gas (e.g., substantially free of oxidant and fuel).

FIG. 4 is a flow chart of an embodiment of an operational process 220 of the system 10 illustrated in FIGS. 1-3. In certain embodiments, the process 220 may be a computer implemented process, which accesses one or more instructions stored on the memory 122 and executes the instructions on the processor 120 of the controller 118 shown in FIG. 2. For example, each step in the process 220 may include instructions executable by the controller 118 of the control system 100 described with reference to FIG. 2.

The process 220 may begin by initiating a startup mode of the SEGR gas turbine system 52 of FIGS. 1-3, as indicated by block 222. For example, the startup mode may involve a gradual ramp up of the SEGR gas turbine system 52 to maintain thermal gradients, vibration, and clearance (e.g., between rotating and stationary parts) within acceptable thresholds. For example, during the startup mode 222, the process 220 may begin to supply a compressed oxidant 68 to the combustors 160 and the fuel nozzles 164 of the combustor section 154, as indicated by block 224. In certain embodiments, the compressed oxidant may include a compressed air, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, or any combination thereof. For example, the oxidant 68 may be compressed by the oxidant compression system 186 illustrated in FIG. 3. The process 220 also may begin to supply fuel to the combustors 160 and the fuel nozzles 164 during the startup mode 222, as indicated by block 226. During the startup mode 222, the process 220 also may begin to supply exhaust gas (as available) to the combustors 160 and the fuel nozzles 164, as indicated by block 228. For example, the fuel nozzles 164 may produce one or more diffusion flames, premix flames, or a combination of diffusion and premix flames. During the startup mode 222, the exhaust gas 60 being generated by the gas turbine engine 156 may be insufficient or unstable in quantity and/or quality. Accordingly, during the startup mode, the process 220 may supply the exhaust gas 66 from one or more storage units (e.g., storage tank 88), the pipeline 86, other SEGR gas turbine systems 52, or other exhaust gas sources.

The process 220 may then combust a mixture of the compressed oxidant, fuel, and exhaust gas in the combustors 160 to produce hot combustion gas 172, as indicated by block 230 by the one or more diffusion flames, premix flames, or a combination of diffusion and premix flames. In particular, the process 220 may be controlled by the control system 100 of FIG. 2 to facilitate stoichiometric combustion (e.g., stoichiometric diffusion combustion, premix combustion, or both) of the mixture in the combustors 160 of the combustor section 154. However, during the startup mode 222, it may be particularly difficult to maintain stoichiometric combustion of the mixture (and thus low levels of oxidant and unburnt fuel may be present in the hot combustion gas 172). As a result, in the startup mode 222, the hot combustion gas 172 may have greater amounts of residual oxidant 68 and/or fuel 70 than during a steady state mode as discussed in further detail below. For this reason, the process 220 may execute one or more control instructions to reduce or eliminate the residual oxidant 68 and/or fuel 70 in the hot combustion gas 172 during the startup mode.

The process 220 then drives the turbine section 156 with the hot combustion gas 172, as indicated by block 232. For example, the hot combustion gas 172 may drive one or more turbine stages 174 disposed within the turbine section 156. Downstream of the turbine section 156, the process 220 may treat the exhaust gas 60 from the final turbine stage 174, as indicated by block 234. For example, the exhaust gas treatment 234 may include filtration, catalytic reaction of any residual oxidant 68 and/or fuel 70, chemical treatment, heat recovery with the HRSG 56, and so forth. The process 220 may also recirculate at least some of the exhaust gas 60 back to the compressor section 152 of the SEGR gas turbine system 52, as indicated by block 236. For example, the exhaust gas recirculation 236 may involve passage through the exhaust recirculation path 110 having the EG processing system 54 as illustrated in FIGS. 1-3.

In turn, the recirculated exhaust gas 66 may be compressed in the compressor section 152, as indicated by block 238. For example, the SEGR gas turbine system 52 may sequentially compress the recirculated exhaust gas 66 in one or more compressor stages 158 of the compressor section 152. Subsequently, the compressed exhaust gas 170 may be supplied to the combustors 160 and fuel nozzles 164, as indicated by block 228. Steps 230, 232, 234, 236, and 238 may then repeat, until the process 220 eventually transitions to a steady state mode, as indicated by block 240. Upon the transition 240, the process 220 may continue to perform the steps 224 through 238, but may also begin to extract the exhaust gas 42 via the EG supply system 78, as indicated by block 242. For example, the exhaust gas 42 may be extracted from one or more extraction points 76 along the compressor section 152, the combustor section 154, and the turbine section 156 as indicated in FIG. 3. In turn, the process 220 may supply the extracted exhaust gas 42 from the EG supply system 78 to the hydrocarbon production system 12, as indicated by block 244. The hydrocarbon production system 12 may then inject the exhaust gas 42 into the earth 32 for enhanced oil recovery, as indicated by block 246. For example, the extracted exhaust gas 42 may be used by the exhaust gas injection EOR system 112 of the EOR system 18 illustrated in FIGS. 1-3. In some embodiments of the SEGR gas turbine system 52, the exhaust gas 42 is recirculated and used to cool the combustor section 154 of the gas turbine engine 150.

FIG. 5 is a schematic diagram of the combustor section 154 that includes various features that are shown in detail in FIGS. 6-10. In particular, the illustrated embodiment depicts an end cover assembly 155 having one or more oxidant supply passages (e.g., a central oxidant passage 157), a baffle assembly 159, an extended casing system 161, and a fuel supply system 163. Elements in FIG. 5 in common with those shown in previous figures are labeled with the same reference numerals. The axial direction of the combustor 160 is indicated by arrow 294, the radial direction is indicated by arrow 296, and the circumferential direction is indicated by arrow 298.

As illustrated in FIG. 5, a compressed oxidant 300 may be provided to the central oxidant passage 157 at a head end portion 302 of the combustor 160. Fuel 70 is provided to the one or more fuel nozzles 164 in the head end portion 302 of the turbine combustor 160. As discussed above, the oxidant 300 and fuel 70 may be mixed prior to injection into the combustor 160 via one or more premix fuel nozzles, injected separately into the combustion chamber 160 via one or more diffusion fuel nozzles, or any combination thereof. Thus, the fuel nozzles 164 may be diffusion fuel nozzles, pre-mix fuel nozzles, or any combination thereof. The compressed oxidant 300 may include air, oxygen, oxygen-enriched air, oxygen-reduced air, or oxygen nitrogen mixtures. In some embodiments, the compressed oxidant 300 may have a concentration of the exhaust gas 42 of less than approximately 10 percent, 5 percent, or 1 percent by volume.

As discussed above, the SEGR gas turbine system 52 may recirculate a portion of the exhaust gas 42 (e.g., compressed exhaust gas 170) through the compressor section 152 and at least part of the combustor section 154 (e.g., one or more combustors 160). In some of the embodiments discussed below, a relatively inert gas 304 (e.g., nitrogen, carbon dioxide, and/or exhaust gas 42, 170) does not circulate through the head end portion 302 of the combustor 160. The inert gas 304 (e.g., exhaust gas 170) from the compressor section 152 may be supplied to a turbine end portion 310 of the combustor 160 rather than to the head end portion 302, thus helping to maintain isolation between the oxidant 300 and the inert gas 304. In some embodiments, the inert gas 304 (e.g., exhaust gas 170) may have less than approximately 10 percent, 5 percent, or 1 percent by volume of oxidant 300 (e.g., oxygen (O₂)). One or more fuels 70 may be supplied to the fuel nozzles 164. For example, the fuel 70 may include, but is not limited to, a gaseous fuel (e.g., natural gas, process gas, methane, hydrogen, carbon monoxide), a liquid fuel (e.g., light distillates, kerosene, heating oil), or any combination thereof.

The compressor section 152 supplies the inert gas 304 (e.g., nitrogen, carbon dioxide, compressed exhaust gas 170) to a compressor discharge casing 305, which encloses at least part of the combustor 160 of the combustor section 154 (e.g., the combustion chamber 168). The inert gas 304 may be substantially inert (e.g., unreactive) relative to the oxidant 300. The combustion chamber 168 is partially enclosed by a combustor cap 306 of the head end portion 302, and a combustor liner 308 (e.g., inner wall) along the axial axis 294 of the combustor 160. The combustor liner 308 extends in the circumferential direction 298 around the combustion chamber 168. The turbine end portion 310 of the combustor 160 guides the combustion gases 172 from combustion of the oxidant 300 and the fuel 70 in the downstream direction 312 to the turbine section 156. In some embodiments, the combustion gases 172 that exit the combustor 160 may be substantially free of oxidant 300 and fuel 70, with a concentration of less than approximately 10, 5, 3, 2, or 1 percent by volume of oxidant 300 and fuel 70. A flow sleeve 314 (e.g., intermediate wall) forms a passage 316 about the combustor liner 308 that enables a fluid (e.g., inert gas 304 such as exhaust gas 170) to flow along the outside of the combustion chamber 168. The passage 316 extends in the circumferential direction 298 around the combustor liner 308, and the flow sleeve 314 extends in the circumferential direction 298 around the passage 316. In some embodiments, the inert gas 304 is a primary cooling media for the combustion chamber 168 and/or a heat sink for the combustion gases 172.

In certain embodiments, the end cover assembly 155 may be configured to receive the compressed oxidant 300 at one or more oxidant passages (e.g., the central oxidant passage 157), and route the compressed oxidant 300 through the head end portion 302 of the combustor 160. For example, the end cover assembly 155 may include 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more oxidant passages 157 to collectively supply greater than or equal to 50, 60, 70, 80, 90, or 100 percent of the oxidant used for combustion in the combustor 160. In the illustrated embodiment, the end cover assembly 155 includes central oxidant passage 157, which may be centered at a central axis 301 of the end cover assembly 155, generally overlapping with the central axis 301, or generally in a central region offset from a perimeter of the end cover assembly 155. As noted above, the central oxidant passage 157 may be configured to receive a range of volumetric flows (e.g., high volumetric flows to low volumetric flows, such as greater than, less than, or equal to 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent) of the oxidant 300 in the axial direction 294 relative to the combustor 160. For example, in certain embodiments, the central oxidant passage 157 may be configured to receive a high volumetric supply of oxidant 300 configured to entirely sustain the combustion process of the combustor 160. As a further example, in certain embodiments, the central oxidant passage 157 may be configured to receive a low volumetric supply of oxidant 300, such as any portion of oxidant 300 that is utilized by the combustion process. Further, it should be noted that in certain embodiments, the head end portion 302 of the combustor 160 may receive a single channel or stream of the oxidant 300, such that all of the oxidant 300 provided to the combustor 160 is routed through the central oxidant passage 157. In certain embodiments, the central oxidant passage 157 is configured to route the oxidant 300 directly to one or more fuel nozzles 164. In the illustrated embodiment, the central oxidant passage 157 routes the oxidant 300 into the baffle assembly 159, as further described with respect to FIGS. 7 and 8. In addition, the illustrated embodiment may be configured to route the oxidant 300 into each of the one or more fuel nozzles 164, as further described with respect to FIG. 6.

In certain embodiments, the baffle assembly 159 has one or more walls (e.g., 337, 339), one or more vanes (e.g., 346), and one or more apertures (e.g., 348) arranged to guide, distribute, and generally route portions of the oxidant 300 into an oxidant section 318 disposed around the flow sleeve 314 downstream of the head end portion 302 of the combustor 160, into the different fuel nozzles 164, and into the combustion chamber 168. Specifically, the oxidant section 318 may be configured to receive a portion of the compressed oxidant 300 from the end cover assembly 155. For example, the end cover assembly 155 may be configured route a portion of the oxidant 300 from the baffle assembly 159 of the end cover assembly 155 into the oxidant section 318 in the downstream direction 312. In certain embodiments, a plurality of mixing holes 330 may direct the portion of the oxidant 300 from the oxidant section 318 and into the combustion chamber 168 to mix (e.g., uniformly mix) the oxidant 300 and fuel 70 from the fuel nozzles 164, to stabilize a flame (e.g., diffusion flame and/or premix flame) from the one or more fuel nozzles 164, and/or to shape a flame within the combustion chamber 168. In some embodiments, the combustor liner 308 may have one or more rows of mixing holes 330 proximate to the head end portion 302. For example, the combustor liner 308 may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of mixing holes 330 about the combustor liner 308, wherein each row may include approximately 1 to 1000 or more holes 330. In some embodiments, the mixing holes 330 are symmetrically spaced about the combustor liner 308. In some embodiments, the position, shape, and/or size of the mixing holes 330 may differ based at least in part on spacing from the combustor cap 306. The shape of the mixing holes 330 may include, but is not limited to, circles, slots, or chevrons, or any combination thereof. The mixing holes 330 may direct a fluid (e.g., oxidant 300, inert gas 304) toward the flame within the combustion chamber 168 to affect the equivalence ratio of the combustion. The flow rate, velocity, and/or direction of the fluid (e.g., oxidant 300, inert gas 304) through the mixing holes 330 may affect various parameters of the flames in the combustion chamber 168. For example, the flow rate and velocity of the fluid may affect mixing of the oxidant 300 and the fuel 70 by shaping the flames in the combustion chamber 168. In some embodiments, a fluid flow through mixing holes 330 angled downstream may form a cooling film (e.g., film cooling) along the combustor liner 308.

The inert gas 304 (e.g., exhaust gas 170) enters a cooling section 320 of the passage 316 in an upstream direction 322 relative to the combustion gases 172 from the turbine end portion 310 of the combustor 160. The passage 316 may be open towards the head end portion 302 and to the discharge casing 305. Specifically, the inert gas 304 enters the flow sleeve 314 from the compressor discharge casing 305 through inlets 332. The inert gas 304 cools the combustor liner 308 through one or more cooling processes. For example, the inert gas 304 flowing through the inlets 332 may cool the combustor liner 308 opposite the inlets 350 by impingement cooling against the liner 308. The inert gas 304 flowing through the cooling section 320 of the passage 316 may cool the liner 308 by convective cooling and/or film cooling. The inert gas 304 may cool an inner surface by flowing through mixing holes 330 and/or dilution holes 334 in the combustor liner 308. In some embodiments, the combustor liner 308 may have one or more rows of dilution holes 334 downstream (e.g., arrow 312) of the mixing holes 330. For example, the combustor liner 308 may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of dilution holes 334 about the combustor liner 308. In some embodiments, the dilution holes 334 are symmetrically spaced about the combustor liner 308. As discussed above with the mixing holes 330, the dilution holes 334 may include varying positions, shapes, and/or sizes based at least in part on spacing from the combustor cap 306.

In some embodiments, an extraction sleeve 326 extends circumferentially 298 around at least part of the flow sleeve 314 and combustor section 154. The extraction sleeve 326 is in fluid communication with the flow sleeve 314, thereby enabling some of the inert gas 304 (e.g., compressed exhaust gas 170) in the flow sleeve 314 to be extracted to an exhaust extraction system 80. The inert gas 304 (e.g., exhaust gas 170) may be bled into the extraction sleeve 326 to control the flow rate of the inert gas 304 within the passage 316. As described in some embodiments above, the gas 304 (e.g., exhaust gas 170) may be recirculated through the SEGR gas turbine system 52 and may be utilized by a fluid injection system 36 for enhanced oil recovery.

FIG. 6 is a schematic diagram of an embodiment of the end cover assembly 155 of FIG. 5, illustrating a compressed oxidant 300 provided to the combustor 160 through the central oxidant passage 157. As noted above, the central oxidant passage 157 may be configured to receive a range of volumetric flow (e.g., 10 to 100 percent) of the oxidant 300 in the axial direction 294 relative to the combustor 160. Specifically, the head end portion 302 of the combustor 160 may receive a single channel or stream of the oxidant 300, such that all of the oxidant 300 provided to the combustor 160 is routed through the central oxidant passage 157. The central oxidant passage 157 may be an annular supply channel, such as a sleeve, a channel, a tube, a bore, a fluid passage, or any combination thereof. The central oxidant passage 157 may be concentric or co-axially arranged with respect to the end cover assembly 155, e.g., centered or substantially centered relative to the central axis 301. Further, the central oxidant passage 157 may include an oxidant inlet 336 configured to receive the compressed oxidant 300. The oxidant inlet 336 may be in fluid communication with the central oxidant passage 157. In certain embodiments, the oxidant inlet 336 of the end cover assembly 155 may be configured to receive a single channel or stream of the oxidant 300, such that all of the oxidant 300 provided to the combustor 160 is routed through the central oxidant passage 157. Furthermore, the oxidant inlet 336 may be configured to receive the supply of the oxidant 300 in the axial direction 294, such that the oxidant 300 is routed into the end cover assembly 155 in the axial direction 294. It should be noted that in certain embodiments, a plurality of oxidant inlets 336 and associated oxidant passages 157 (e.g., 2, 3, 4, 5, 6, or more) may be arranged at the head end portion 302 of the end cover assembly 155, such that the end cover assembly 155 routes separate streams of oxidant to the different fuel nozzles 164, the oxidant section 318, the combustion chamber 168, or any combination thereof.

In certain embodiments, the central oxidant passage 157 may be configured to receive a wide range of volumetric or mass flows (e.g., 10 to 100 percent) of the oxidant 300. For example, in situations where the combustor 160 utilizes a large amount of oxidant 300 during the combustion process, the central oxidant passage 157 may facilitate receiving a sufficient supply of the oxidant 300 at the oxidant inlet 336. Indeed, the central oxidant passage 157 may be configured to handle a high volumetric flow of the oxidant 300 through the single oxidant inlet 336, such as an amount of high volumetric flow sufficient to sustain the combustion process within the combustor 160. It should be noted that in certain embodiments, a plurality of oxidant inlets 336 (e.g., 2, 3, 4, 5, 6, or more) may be arranged at the head end portion 302 of the end cover assembly 155, such that each oxidant inlet 336 is configured to axially receive the oxidant 300 and such that each oxidant inlet 336 is in fluid communication with the central oxidant passage 157.

In certain embodiments, the central oxidant passage 157 of the end cover assembly 155 is configured to route the supply of oxidant 300 from the central oxidant passage 157 and into the baffle assembly 159. Specifically, the central oxidant passage 157 may be in fluid communication with the baffle assembly 159, as further described with respect to FIGS. 7 and 8. The baffle assembly 159 may be configured to receive and distribute the oxidant 300 from the central oxidant passage 157 into each of the one or more fuel nozzles 164, into the oxidant section 318, and/or into the combustion chamber 168. Specifically, the baffle assembly 159 may include a baffle body 338 (e.g., a hollow cylindrical body, cup shaped body, or annular wall) defining a baffle channel 340. For example, the baffle body 338 of the baffle assembly 159 may include a side wall 337 extending about the central axis 301 and the baffle channel 340, and a downstream end wall 339 at an axial end of the side wall 337. Each of these walls 337 and 339 may include one or more apertures 348 to help distribute the oxidant flow from the baffle channel 340. The baffle channel 340 may be an annular supply channel, such as a sleeve, a tube, a bore, a fluid passage, or any combination thereof. The baffle body 338 may be configured as a cylindrical shell (or any shell structure or wall extending about the central axis 301) that defines a volume for the baffle channel 340. For example, the baffle assembly 159 may be concentrically or co-axially arranged with respect to the central oxidant passage 157 and/or the end cover assembly 155, e.g., centered or substantially centered relative to the central axis 301. In certain embodiments, the baffle channel 340 may include one or more passageways 342 that allow components of the fuel supply system 163 to extend through the baffle assembly 159 from the head end portion 302 in the downstream direction 312 along the axial direction 294, as further described with respect to FIG. 9.

In certain embodiments, the baffle assembly 159 may include a plurality of flow guides, panels, or vanes 346 that are configured to direct the oxidant 300 received from the central oxidant passageway 157. Specifically, the vanes 346 may be arranged and configured to direct (e.g., guide and/or turn) the flow of the oxidant 300 from the baffle channel 340 and into a plurality of oxidant apertures 348. The plurality of oxidant apertures 348 may be disposed through the side wall 337 and/or the end wall 339 of the baffle body 338, and may be configured to direct a portion of the oxidant 300 into and/or around one or more fuel nozzles 164. In some embodiments, the baffle assembly 159 may have one or more rows of oxidant apertures 348 proximate to the fuel nozzles 164. For example, the baffle assembly 159 may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of oxidant apertures 348 about the baffle body 338, wherein each row may include approximately 1 to 1000 or more apertures 348. In some embodiments, the oxidant apertures 348 are symmetrically and/or uniformly spaced about the baffle body 338. In some embodiments, the position, shape, and/or size of the oxidant apertures 348 may differ based at least in part on spacing from the fuel nozzles 164. Thus, the oxidant apertures 348 help to distribute the oxidant among the fuel nozzles 164, while the fuel nozzles 164 also receive fuel from the fuel supply system 163.

In certain embodiments, the fuel supply system 163 includes an outer fuel nozzles supply inlet 350, a central fuel nozzle supply inlet 352, and one or more fuel supply passages 354. The outer fuel nozzles supply inlet 350 may be configured to receive the fuel 70 and route the fuel 70 to one or more supply chambers 356. Each supply chamber 356 may be associated with a single outer fuel nozzle 358. Further, the central fuel nozzle supply inlet 352 may be configured to receive the fuel 70 and route the fuel 70 directly to the central fuel nozzle 360 via a central fuel supply passage 362. As noted above, the fuel supply passages 354 (including the central fuel supply passage 362), may be routed through the baffle assembly 159 via the passageways 342. In this manner, the fuel supply passages 354 may provide a flow path for the fuel 70 through the head end portion 302 of the combustor 160 and through the end cover assembly 155. Specifically, the fuel 70 is routed from the fuel supply, through the inlets (e.g., the outer fuel nozzles supply inlet 350, the central fuel nozzle supply inlet 352), and into the fuel nozzles 164 before being injected into the combustion chamber 168. In certain embodiments, the fuel nozzles 164 include a fuel tip 364 disposed at a downstream end of the fuel supply passages 354, 362. The tip 354 may include a plurality of passages extending therethrough that allow the fuel 70 to flow through the tip 364 and into the combustion chamber 168.

In certain embodiments, the fuel 70 flowing through the tip 364 may be configured to mix with the oxidant 300 routed from the plurality of oxidant apertures 348 in the baffle assembly 159 and into each one of the fuel nozzles 164. Specifically, the baffle assembly 159 may be in fluid communication with each of the fuel nozzles 164, thereby routing a portion of the oxidant 300 through the oxidant apertures 348 and into a plurality of oxidant ports 366 disposed on each of the fuel nozzles 164. In this manner, the fuel nozzles 164 may be configured to mix the oxidant 300 and the fuel 70 before injecting the mixture into the combustion chamber 168. As noted above with respect to FIG. 5, in certain embodiments, a portion of the oxidant 300 is routed from the baffle assembly 159 and into an oxidant section 318 disposed around the flow sleeve 314 downstream of the head end portion 302 of the combustor 160. Specifically, the oxidant section 318 may be configured to receive a portion of the compressed oxidant 300 from the plurality of oxidant apertures 348 in the baffle assembly 159. In these situations, the plurality of mixing holes 330 may direct the portion of the oxidant 300 from the oxidant section 318 and into the combustion chamber 168 to mix (e.g., uniformly mix) the oxidant 300 and fuel 70 from the fuel nozzles 164.

FIG. 7 is a schematic diagram of an embodiment of the central oxidant passage 157 of FIG. 6, taken within line 7-7, wherein the central oxidant passage 157 includes a heat shield 367 (e.g., annular heat shield) and a flow conditioner 368 (e.g., annular flow conditioner). The heat shield 367 may include a sleeve, coating, or layer of material configured to block or resist heat transfer from the oxidant flowing through the central oxidant passage 157 and the end cover assembly 155. For example, the heat shield 367 may be removably coupled (e.g., threaded, bolted, or fastened), fixedly coupled (e.g., welded), or coated onto an interior surface 369 of the central oxidant passage 157. The flow conditioner 368 may be coupled directly or indirectly to the end cover assembly 155. For example, the flow conditioner 368 may be removably coupled (e.g., threaded, bolted, or fastened) or fixedly coupled (e.g., welded) to the end cover assembly 155 and/or the heat shield 367 in the central oxidant passage 157. In the illustrated embodiment, the flow conditioner 368 includes an inner wall 370 surrounded by an outer wall 371 in a coaxial or concentric arrangement (e.g., coaxial annular walls). The flow conditioner 368 also includes a plurality of oxidant ports or openings 372 configured to help condition and distribute (e.g., uniformly distribute) the oxidant flow from the central oxidant passage 157 into the baffle assembly 159. The openings 372 may be disposed on the inner wall 370, the outer wall 371, and/or an axial end wall 373. In certain embodiments, the axial end wall 373 may cover 0, 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent of an end of the flow conditioner 368. The outer wall 371 may be an annular or hollow cylindrical wall extending parallel to the axis 301, whereas the inner wall 370 may gradually diverge (e.g., curve or taper) away from the axis 301 in the downstream direction of oxidant flow toward the end of the flow conditioner 368. For example, the inner wall 370 may include a first wall portion 374 (e.g., straight annular or hollow cylindrical wall) followed by a second wall portion 375 (e.g., diverging annular wall, funnel shaped wall, conical wall, or parabolic wall). The second wall portion 375 gradually diverges (e.g., tapers or curves) outwardly away from the axis 301 and the first wall portion 370 toward the outer wall 371. In the illustrated embodiment, the second wall portion 375 of the inner wall 370 intersects the outer wall 371 at the downstream end of the flow conditioner 368.

In certain embodiments, the flow conditioner 368 may be configured to break up large scale flow structures (e.g., vortices) of the compressed oxidant 300 into smaller scale flow structures as the compressed oxidant 300 is routed into the central oxidant passage 157, through the oxidant openings 372, and to the baffle assembly 159. In addition, the flow conditioner 368 may be configured to guide or channel the oxidant flow in a manner that provides more uniform oxidant flow distribution to the baffle assembly 159, thereby also improving the uniformity of oxidant flow into each individual fuel nozzle 164. For example, the incoming oxidant flow may be split between a first or central oxidant flow passing through the inner wall 370 of the flow conditioner 368 and a second or outer oxidant flow passing between the inner and outer walls 370 and 371 (e.g., in an annular passage 376). As the first flow passes through flow conditioner 368, the inner wall 370 gradually increases in cross-sectional area from the first wall portion 374 to the second wall portion 375 (e.g., diverging section), thereby helping to diffuse, expand, and distribute the oxidant flow. The first flow passing through flow conditioner 368 also may pass through openings 372 in the inner wall 370 (e.g., first and/or second wall portions 374, 375), the end wall 373, or a combination thereof, thereby further helping to condition and distribute the oxidant flow. As the second flow passes through flow conditioner 368 (e.g., in annular passage 376), the inner wall 370 turns (e.g., tapers, curves, or bends) away from the axis 301 toward the outer wall 371, thereby gradually guiding the oxidant flow to turn in a radial outward direction away from the axis 301 through the openings 372 in the outer wall 371. In this manner, the flow conditioner 368 guides the second flow in the passage 376 to penetrate much further in the radial direction within the baffle assembly 159. Together, the inner and outer walls 370 and 371 and openings 372 of the flow conditioner 368 facilitate distribution and conditioning of the oxidant flow, thereby providing improved distribution of the oxidant flow among the fuel nozzles 164, the oxidant section 318, and the combustion chamber 168.

The plurality of oxidant openings 372 may direct the oxidant 300 from the flow conditioner 368 and into the baffle assembly 159. In some embodiments, the inner wall 370, the outer wall 371, and/or the end wall 373 of the flow conditioner 368 may have one or more rows of oxidant openings 372 proximate to the baffle assembly 159. For example, the inner wall 370, the outer wall 371, and/or the end wall 373 of the flow conditioner 368 may have approximately 1 to 1000, 1 to 500, 1 to 100, 1 to 10, or any other number of rows of oxidant openings 372, wherein each row may include approximately 1 to 1000 or more openings 372. In some embodiments, the oxidant openings 372 are symmetrically spaced about the axis 301. In some embodiments, the position, shape, and/or size of the oxidant openings 372 may differ based at least in part on spacing from the baffle assembly 159.

In certain embodiments, the central oxidant passage 157 may include or exclude the heat shield 367 configured to thermally shield components of the end cover assembly 155 (e.g., the fuel supply system 163) from the high temperatures associated with the compressed oxidant 300. For example, the heat shield 367 may be an annular shield disposed on the interior surface 369 of the central oxidant passage 157 and configured to substantially thermally isolate the central oxidant passage 157 from components of the end cover assembly 155. That is, the heat shield 367 may act as a thermal barrier to block the high temperatures of the oxidant 300 provided to the end cover assembly 155 from thermally interacting with the lower temperatures of the fuel 70 provided to the end cover assembly 155. In certain embodiments, the heat shield 367 may be a heat shield coating applied to the interior surface 369 of the central oxidant passage 157.

In certain embodiments, in addition to the heat shield 367, the end cover assembly 155 may include a thermal groove 378 concentrically disposed around the central oxidant passage 157. Specifically, the thermal groove 378 may additionally be configured to provide a thermal separation between the high temperatures of the oxidant 300 provided to the central oxidant passage 157 from thermally interacting with the lower temperatures of the fuel 70 provided to the one or more supply chambers 356. In particular, the thermal groove 378 may partially extend into the end cover assembly 155, such that a thermal barrier is created a depth 377 into the end cover assembly 155 around the central oxidant passage 157.

FIG. 8 is a schematic diagram of an embodiment of the central oxidant passage 157 of FIG. 6 configured to route the oxidant 300 to the baffle assembly 159. Specifically, in the illustrated embodiment of the central oxidant passage 157, the central oxidant passage 157 may include the flow conditioner 368 of FIG. 7 without the inner wall 370. As a result, in the embodiment of FIG. 8, the oxidant flow is not split into first and second flows associated with the coaxial inner and outer walls 370 and 371. Instead, all of the oxidant flow passes through the outer wall 371 of the flow conditioner 368, and then exits the flow conditioner through openings 372 in the outer wall 371 and/or the end wall 373. In certain embodiments, the end wall 373 may be completely open to the full diameter of the outer wall 371, and thus only a single opening 372 may exist at the end wall 373. In other embodiments, the end wall 373 may include a plurality of openings of equal, smaller, or larger diameter than the openings 372 in the outer wall 371. As the oxidant flow passes through the flow conditioner 368 in FIG. 8, the oxidant flow is conditioned and distributed in the radial outward direction through openings 372 in the outer wall 372 and an axial direction through one or more openings 372 in the end wall 373. In this manner, the flow conditioner 368 may be configured to help distribute the oxidant 300 throughout the baffle assembly 159 for improved distribution to the fuel nozzles 164, the oxidant section 318, and the combustion chamber 168.

FIG. 9 is a schematic diagram of an embodiment of the extended casing system 161 of FIG. 6, where the extended casing system 161 includes a flange 380 (e.g., annular flange), an outer expansion wall 382 (e.g., annular wall), an inner expansion wall 384 (e.g., annular wall), and a flex space 386 (e.g., annular space). In certain embodiments, the extended casing system 161 may also include a baffle wall 388. In particular, the extended casing system 161 includes a volume of space 390 configured to house components of the end cover assembly 155, such as the central oxidant passage 157, the baffle assembly 159, and the fuel supply system 163. Further, in certain embodiments, the extended casing system 161 may be configured to provide flexibility (e.g., resiliency to undergo thermal expansion and contraction) for the components of the end cover assembly 155 during operation of the combustor 160. For example, during operation of the combustor 160, the end cover assembly 155 may be configured to receive fluids (e.g., the oxidant 300, the fuel 70) of varying temperatures and pressures, while also being surrounded by ambient temperatures (e.g., external to end cover assembly 155). For example, the oxidant 300 may be provided to the central oxidant passage 300 at high temperatures, the fuel 70 may be provided to the outer fuel nozzles supply inlet 350 or the central fuel nozzle supply inlet 352 at lower temperatures, and the ambient air surrounding the end cover assembly 155 also may be at a relatively low temperature compared with the oxidant 300. Accordingly, during operation of the combustor 160, the temperature gradients caused by the fluids (e.g., the oxidant 300, the fuel 70) may cause thermal expansion within the end cover assembly 155. In certain embodiments, features of the extended casing system 161 may be configured to flex or expand in response to thermal strains and/or temperature gradients among the components of the end cover assembly 155. Further, the features of the extended casing system 161 may be configured to retract when the thermal strain and/or temperature gradient is minimized. In this manner, the extended casing system 161 may provide some flexibility to the components of the end cover assembly 155 as the components adjust to the temperature gradient and/or thermal strain caused by the intake fluids.

In certain embodiments, the outer expansion wall 382 and the inner expansion wall 384 may be configured to expand into the flex space 386 to accommodate possible thermal expansion of the components of the end cover assembly 155. For example, the end cover assembly 155 may be configured to receive the fuel 70 at lower temperatures within the one or more supply chambers 356, and may route the fuel 70 through the one or more fuel supply passages 354 to the fuel nozzles 164. Further, the end cover assembly 155 may be configured to receive the oxidant 300 at higher temperatures within the central oxidant passage 157, and may route the oxidant 300 through the baffle assembly 159, and to the combustion chamber 158. In certain embodiments, portions of the oxidant 300 may be routed from the plurality of oxidant apertures 348 in the baffle assembly 159 and into the flex space 386 of the end cover assembly 155. Indeed, components of the end cover assembly 155 (e.g., the one or more supply chambers 356, the one or more fuel supply passages 354, the baffle system 159) may thermally expand in response to the temperature gradient between the fuel 70 and the oxidant 300 within the end cover assembly 155.

Accordingly, in certain embodiments, the outer expansion wall 382, the inner expansion wall 384, and the baffle wall 388 may be configured to expand into the flex space 386 to accommodate the possible thermal expansion of the components of the end cover assembly 155. In certain embodiments, the dimensions of the walls 382, 384, and 388 may be provided some flexibility for the thermal expansion. For example, each of the walls 382, 384, and 388 may be thin elongated walls (e.g., thin annular walls), such that, for example, an axial height 390 is greater than a thickness or radial width 392. For example, in certain embodiments, a ratio of the height 390 relative to the width 392 (e.g., height/width) of the wall 382 may be greater than approximately 5, 10, 15, or 20. By further example, in certain embodiments, the thickness or radial width 392 of the walls 382, 384, and 388 may be relatively thin as compared with surrounding structures of the end cover assembly 155. As a result, the relatively thinner thickness 392 of the walls 382, 384, and 388 relative to surrounding structures may result in the walls 382, 384, and 388 preferentially flexing (e.g., thermally expanding or contracting) while the surrounding structures remain generally stationary. In particular, the thin walls 382, 384, and 388 facilitate the thermal expansion of the walls into the flex space 386, which serves as an open buffer zone to enable flexing without any contact between the walls 382, 384, and 386. Further, it should be noted that the height 390 of the outer expansion wall 382 may additionally be configured to increase the volume of space 390 within the end cover assembly 155, thereby facilitating the housing of the components of the end cover assembly 155 (e.g., the central oxidant passage 157, the baffle assembly 159, and the fuel supply system 163, etc.).

In certain embodiments, the extended casing system 161 may include the flange 380 configured to couple and secure the end cover assembly 155 to a portion 394 of the compressor section 152 of the gas turbine engine 150. The flange 380 may be a protruding feature that facilitates the coupling of the end cover assembly 155 to the compressor section 152. Particularly, the attachment or coupling may be facilitated by one or more attachment features 396. The attachment features 396 may include threaded fasteners, bolts, snap rings, support structures, welds, etc. Additionally, the attachment or coupling may be done via adhesion, via welding, via fasteners, or via any other suitable mount. It should be noted that components within the end cover assembly 155 may also utilize the attachment features 396 (e.g., threaded fasteners such as bolts) to secure or couple to other components within the end cover assembly 155. For example, the central oxidant passage 157 may utilize one of the attachment features 396 or techniques described above to secure or couple with the baffle assembly 159.

FIG. 10 is a cross-sectional view of an embodiment of the end cover assembly 155 of FIG. 5, taken along line 10-10 of FIG. 6, illustrating the fuel supply system 163. In particular, the fuel supply system 163 includes the outer fuel nozzles supply inlet 350, the central fuel nozzle supply inlet 352, the one or more fuel supply passages 354, and the one or more supply chambers 356. The illustrated embodiment depicts the fuel 70 routed from the fuel supply to the outer fuel nozzles supply inlet 350 and the central fuel nozzle supply inlet 352. Specifically, the central fuel nozzle supply inlet 352 may be configured to receive the fuel 70, and route the fuel directly to the central fuel nozzle 360 via a central fuel supply passage 362. In addition, the outer fuel nozzles supply inlet 350 may be configured to receive the fuel 70 and route the fuel 70 to one or more supply chambers 356, where each supply chamber 356 is associated with a single outer fuel nozzle 358.

In particular, the outer fuel nozzles supply inlet 350 may be configured to route the fuel 70 to the one or more supply chambers 356 through a fuel manifold 400 integrated within (e.g., formed as one-piece with) the end cover assembly 155. In certain embodiments, the fuel manifold 400 may be coupled to each of the one or more supply chambers 356. Further, the fuel manifold 400 may include a variable cross-section that decreases in size for supply chambers 356 further away from the outer fuel nozzles supply inlet 350. For example, in the illustrated fuel manifold, a first cross-section 402 of the fuel manifold 400 proximate to a first supply chamber 404 is greater than a second cross-section 406 proximate to a second supply chamber 408, because the second supply chamber 408 is further away from the first supply chamber 404. It should be noted that the variable cross-section of the fuel manifold 400 may be configured to maintain a constant fuel flow velocity 410 for the fuel 70 supplied to each supply chamber 356. Accordingly, decreasing the cross-section of the fuel manifold 400 for a supply chamber 356 further away from the outer fuel nozzles supply inlet 350 increases the fuel flow velocity 410 of the fuel 70 provided to the supply chamber 356 further away.

Technical effects of the present approach include an end cover assembly 155 configured to route the oxidant 300 and the fuel 70 through the head end portion 302 of the gas turbine engine 150 and into one or more fuel nozzles 164. The end cover assembly 155 includes the central oxidant passage 157, the baffle assembly 159, the extended casing system 161, and the fuel supply system 163. The end cover assembly 155 may be configured to axially receive and route a range of oxidant volumetric flows (e.g., high volumetric flows of oxidant and/or low volumetric flows of oxidant) through the head end portion 302 of the combustor 160. Specifically, the end cover assembly 155 may be configured to receive the volumetric ranges of the oxidant 300 at a single central location (e.g., the central oxidant passage 157) within the head end portion 302 of the combustor 160, rather than through various locations throughout the head end portion 302 of the combustor 160. The baffle assembly 159 may include the plurality of oxidant holes 348 configured to route and direct the supply of the oxidant 300 through the end cover assembly 155 and into each of the one or more fuel nozzles 164. The fuel supply system 163 includes the outer fuel nozzles supply inlet 350, the central fuel nozzle supply inlet 352, the one or more fuel supply passages 354, and the plurality of fuel nozzles 164. In particular, the fuel supply system 163 may be configured to route the fuel 70 through the head end portion 302 of the combustor 160 and into each of the plurality of nozzles 164. In certain embodiments, the one or more fuel supply passages 354 are configured to extend through the baffle assembly 159 of the end cover assembly 155.

Technical effects of the present approach also include the extended casing system 161 configured to house the central oxidant passage 157, the baffle assembly 159, and the fuel supply system 163. The extended casing system includes the flange 380, the outer expansion wall 382, the inner expansion wall 384, the baffle wall 388, and the flex space 386. In certain embodiments, features of the extended casing system 161 may be configured to flex or expand in response to thermal strains and/or temperature gradients among the components of the end cover assembly 155. For example, the outer expansion wall 382 and the inner expansion wall 384 may be configured to expand into the flex space 386 to accommodate possible thermal expansion of the components of the end cover assembly 155.

ADDITIONAL EMBODIMENTS

The present embodiments provide a system and method for controlling combustion and emissions in a gas turbine engine with exhaust recirculation. It should be noted that any one or a combination of the features described above may be utilized in any suitable combination. Indeed, all permutations of such combinations are presently contemplated. By way of example, the following clauses are offered as further description of the present disclosure:

Embodiment 1

A system having a gas turbine engine is provided. The gas turbine engine includes a turbine and a combustor coupled to the turbine. The combustor includes a combustion chamber, one or more fuel nozzles upstream from the combustion chamber, and a head end having an end cover assembly. The end cover assembly includes an oxidant inlet configured to receive an oxidant flow, a central oxidant passage, and at least one fuel supply passage. The central oxidant passage is in fluid communication with the oxidant inlet, and the central oxidant passage is configured to route the oxidant flow to the one or more fuel nozzles. The at least one fuel supply passage is configured to receive a fuel flow and route the fuel flow into the one or more fuel nozzles.

Embodiment 2

The system of embodiment 1, wherein the end cover assembly comprises a baffle assembly in fluid communication with the central oxidant passage.

Embodiment 3

The system of embodiment 2, wherein the baffle assembly comprises a baffle channel defined by a baffle shell, wherein the baffle channel is in fluid communication with the central oxidant passage.

Embodiment 4

The system of embodiment 3, wherein the baffle shell comprises a plurality of oxidant apertures disposed through a wall of the baffle shell, wherein the plurality of oxidant apertures is configured to distribute the oxidant flow into a plurality of streams of oxidant flows.

Embodiment 5

The system of embodiment 3, wherein the baffle assembly is configured to route the plurality of streams of oxidant flows into a plurality of fuel nozzles.

Embodiment 6

The system of embodiment 1, wherein the central oxidant passage comprises a flow conditioner comprising a plurality of openings, a diverging wall, or a combination thereof.

Embodiment 7

The system of embodiment 1, wherein the central oxidant passage comprises a heat shield configured as a thermal barrier between the oxidant flow at a first temperature and the fuel flow at a second temperature, wherein the first temperature is greater than the second temperature.

Embodiment 8

The system of embodiment 1, wherein the end cover assembly comprises a thermal groove configured as a thermal barrier between the oxidant flow at a first temperature and the fuel flow at a second temperature, wherein the first temperature is greater than the second temperature.

Embodiment 9

The system of embodiment 1, wherein the end cover assembly comprises an extended casing system comprising one or more expansion walls that expand or contract in response to a temperature gradient between the oxidant flow and the fuel flow.

Embodiment 10

The system of embodiment 9, wherein the one or more expansion walls expand and contract into a flex space disposed within the end cover assembly.

Embodiment 11

The system of embodiment 1, where the turbine is driven by combustion gases generated as a result of combusting the fuel flow with the oxidant flow within the combustion chamber, where the turbine outputs an exhaust gas, where the gas turbine engine comprises an exhaust gas compressor driven by the turbine, and where the exhaust gas compressor is configured to compress and to route the exhaust gas to the combustor.

Embodiment 12

The system of embodiment 11, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.

Embodiment 13

The system of embodiment 11, comprising an exhaust gas extraction system coupled to the gas turbine engine and a hydrocarbon production system coupled to the exhaust gas extraction system.

Embodiment 14

A system including an end cover assembly is provided. The end cover assembly is configured to mount at a head end of a turbine combustor. The end cover assembly includes an oxidant inlet, a central oxidant passage, and at least one fuel supply passage. The oxidant inlet configured to receive an oxidant flow. The central oxidant passage in fluid communication with the oxidant inlet and is configured to route the oxidant flow to one or more fuel nozzles. The at least one fuel supply passage configured to receive a fuel flow, where the at least one fuel supply passage is configured to route the fuel flow into the one or more fuel nozzles.

Embodiment 15

The system of embodiment 14, wherein the end cover assembly comprises an expansion wall configured to expand or contract into a flex space of the end cover assembly in response to a temperature gradient between the oxidant flow at a first temperature and the fuel flow at a second temperature.

Embodiment 16

The system of embodiment 14, wherein the end cover assembly comprises a baffle assembly in fluid communication with the central oxidant passage, and wherein the baffle assembly comprises a baffle channel in fluid communication with the central oxidant passage.

Embodiment 17

The system of embodiment 16, wherein the baffle assembly comprises a baffle shell with a plurality of oxidant apertures disposed through a wall of the baffle shell.

Embodiment 18

The system of embodiment 14, wherein the central oxidant passage comprises a heat shield configured as a thermal barrier between the oxidant flow and the fuel flow.

Embodiment 19

The system of embodiment 14, wherein the end cover assembly comprises a thermal groove configured as a thermal barrier between the oxidant flow and the fuel flow.

Embodiment 20

The system of embodiment 14, including a gas turbine engine is provided. The gas turbine engine includes a combustor having the end cover assembly. The gas turbine engine also includes a turbine driven by combustion gases generated as a result of combusting the fuel flow with the oxidant flow within the combustion chamber, where the turbine outputs an exhaust gas. The gas turbine engine also includes an exhaust gas compressor driven by the turbine, where the exhaust gas compressor is configured to compress and to route the exhaust gas to the combustor.

Embodiment 21

The system of embodiment 20, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.

Embodiment 22

The system of embodiment 21, comprising an exhaust gas extraction system coupled to the gas turbine engine and a hydrocarbon production system coupled to the exhaust gas extraction system.

Embodiment 23

A method is provided. The method includes receiving an oxidant flow into an oxidant inlet of an end cover assembly of a turbine combustor of a gas turbine engine. The method also includes routing the oxidant flow from the oxidant inlet through a central oxidant passage in the end cover assembly and distributing the oxidant flow from the central oxidant passage into a plurality of fuel nozzles.

Embodiment 24

The method of embodiment 23, comprising conditioning the oxidant flow in the central oxidant passage by routing the oxidant flow through a plurality of oxidant openings, turning the oxidant flow, or a combination thereof.

Embodiment 25

The method of embodiment 23, comprising flexing a portion of the end cover assembly into a flex space to accommodate thermal expansion or thermal contract.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims. 

1. A system, comprising: a gas turbine engine, comprising: a turbine; and a combustor coupled to the turbine, wherein the combustor comprises a combustion chamber, one or more fuel nozzles upstream from the combustion chamber, and a head end having an end cover assembly, wherein the end cover assembly comprises: an oxidant inlet configured to receive an oxidant flow; a central oxidant passage in fluid communication with the oxidant inlet, wherein the central oxidant passage is configured to route the oxidant flow to the one or more fuel nozzles; and at least one fuel supply passage configured to receive a fuel flow, wherein the at least one fuel supply passage is configured to route the fuel flow into the one or more fuel nozzles.
 2. The system of claim 1, wherein the end cover assembly comprises a baffle assembly in fluid communication with the central oxidant passage.
 3. The system of claim 2, wherein the baffle assembly comprises a baffle channel defined by a baffle shell, wherein the baffle channel is in fluid communication with the central oxidant passage.
 4. The system of claim 3, wherein the baffle shell comprises a plurality of oxidant apertures disposed through a wall of the baffle shell, wherein the plurality of oxidant apertures is configured to distribute the oxidant flow into a plurality of streams of oxidant flows.
 5. The system of claim 3, wherein the baffle assembly is configured to route the plurality of streams of oxidant flows into a plurality of fuel nozzles.
 6. The system of claim 1, wherein the central oxidant passage comprises a flow conditioner comprising a plurality of openings, a diverging wall, or a combination thereof.
 7. The system of claim 1, wherein the central oxidant passage comprises a heat shield configured as a thermal barrier between the oxidant flow at a first temperature and the fuel flow at a second temperature, wherein the first temperature is greater than the second temperature.
 8. The system of claim 1, wherein the end cover assembly comprises a thermal groove configured as a thermal barrier between the oxidant flow at a first temperature and the fuel flow at a second temperature, wherein the first temperature is greater than the second temperature.
 9. The system of claim 1, wherein the end cover assembly comprises an extended casing system comprising one or more expansion walls that expand or contract in response to a temperature gradient between the oxidant flow and the fuel flow.
 10. The system of claim 9, wherein the one or more expansion walls expand and contract into a flex space disposed within the end cover assembly.
 11. The system of claim 1, wherein the turbine is driven by combustion gases generated as a result of combusting the fuel flow with the oxidant flow within the combustion chamber, wherein the turbine outputs an exhaust gas, wherein the gas turbine engine comprises an exhaust gas compressor driven by the turbine, wherein the exhaust gas compressor is configured to compress and to route the exhaust gas to the combustor.
 12. The system of claim 11, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.
 13. The system of claim 11, comprising an exhaust gas extraction system coupled to the gas turbine engine and a hydrocarbon production system coupled to the exhaust gas extraction system.
 14. A system, comprising: an end cover assembly configured to mount at a head end of a turbine combustor, wherein the end cover assembly comprises: an oxidant inlet configured to receive an oxidant flow; a central oxidant passage in fluid communication with the oxidant inlet, wherein the central oxidant passage is configured to route the oxidant flow to one or more fuel nozzles; and at least one fuel supply passage configured to receive a fuel flow, wherein the at least one fuel supply passage is configured to route the fuel flow into the one or more fuel nozzles.
 15. The system of claim 14, wherein the end cover assembly comprises an expansion wall configured to expand or contract into a flex space of the end cover assembly in response to a temperature gradient between the oxidant flow at a first temperature and the fuel flow at a second temperature.
 16. The system of claim 14, wherein the end cover assembly comprises a baffle assembly in fluid communication with the central oxidant passage, and wherein the baffle assembly comprises a baffle channel in fluid communication with the central oxidant passage.
 17. The system of claim 16, wherein the baffle assembly comprises a baffle shell with a plurality of oxidant apertures disposed through a wall of the baffle shell.
 18. The system of claim 14, wherein the central oxidant passage comprises a heat shield configured as a thermal barrier between the oxidant flow and the fuel flow.
 19. The system of claim 14, wherein the end cover assembly comprises a thermal groove configured as a thermal barrier between the oxidant flow and the fuel flow.
 20. The system of claim 14, comprising: a gas turbine engine, comprising: a combustor having the end cover assembly; a turbine driven by combustion gases generated as a result of combusting the fuel flow with the oxidant flow within the combustion chamber, wherein the turbine outputs an exhaust gas; and an exhaust gas compressor driven by the turbine, wherein the exhaust gas compressor is configured to compress and to route the exhaust gas to the combustor.
 21. The system of claim 20, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.
 22. The system of claim 21, comprising an exhaust gas extraction system coupled to the gas turbine engine and a hydrocarbon production system coupled to the exhaust gas extraction system.
 23. A method, comprising: receiving an oxidant flow into an oxidant inlet of an end cover assembly of a turbine combustor of a gas turbine engine; routing the oxidant flow from the oxidant inlet through a central oxidant passage in the end cover assembly; and distributing the oxidant flow from the central oxidant passage into a plurality of fuel nozzles.
 24. The method of claim 23, comprising conditioning the oxidant flow in the central oxidant passage by routing the oxidant flow through a plurality of oxidant openings, turning the oxidant flow, or a combination thereof.
 25. The method of claim 23, comprising flexing a portion of the end cover assembly into a flex space to accommodate thermal expansion or thermal contract. 